High temperature solvent separation with advanced strippers and direct contact condensers.

Abstract

The methods and systems described herein improve the energy efficiency and cost of separating components from hot solvents. The heat exchanger used to capture heat from the stripper before the final condensation step may be replaced with an additional packing section. This additional packing section may be at the top of the stripper column and may function as a direct contact condenser. In addition, the cold rich split may flow to the additional packing section rather than being mixed with the warm rich bypass. This direct contact condenser configuration increases energy efficiency and reduces capital costs.

Description

[Technical Field]

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of and priority to U.S. Provisional Application No. 63 / 440,811, filed January 24, 2023, entitled "HIGH TEMPERATURE SOLVENT SEPARATION WITH ADVANCED STRIPPER AND DIRECT CONTACT CONDENSER," the entire contents of which are incorporated herein by reference for all purposes.

[0002] FIELD OF THE INVENTION Embodiments of the present invention are in the field of chemical separation processes and systems.Embodiments of the present invention generally relate to separating carbon dioxide from high temperature solvents and water. [Background technology]

[0003] Global climate change has spurred initiatives to reduce emissions of acid gases, such as carbon dioxide (CO2). Acid gas removal by absorption / stripping is a commercially promising technology because it is well suited to sequestering CO2. CO2 emissions, such as gas streams produced by coal-fired power plants and fossil-fuel-powered vehicles, are produced by a variety of different processes. Removal of CO2 from such gaseous streams can be a costly process, potentially increasing the cost of electricity generation by 50% or more. Therefore, technological improvements that reduce the costs associated with CO2 removal are highly desirable.

[0004] Gas absorption is a process in which soluble components of a gas mixture are dissolved into a liquid. Stripping is essentially the reverse of absorption, as it involves converting volatile components from a liquid mixture into a gas. A typical CO2 removal process uses absorption to remove CO2 from combustion gases, followed by stripping to regenerate a solvent and capture the CO2 contained in the solvent. Once CO2 is removed from combustion gases and other gases, it can be captured and compressed for use in a number of applications, including sequestration, methanol production, and tertiary oil recovery.

[0005] Cost-effective and energy-efficient methods and systems for separating carbon dioxide are desirable. These and other improvements are addressed by embodiments of the present invention. Summary of the Invention

[0006] The methods and systems described herein improve the energy efficiency and cost of separating components from hot solvents. For example, the heat exchanger used to capture heat from the stripper overhead gas stream prior to the final condensation step may be replaced with an additional packing or tray section. This additional packing or tray section may be at the top of the stripper column and may function as a direct contact condenser. In addition, the cold rich split may flow to the additional packing or tray section rather than being mixed with the warm rich bypass. This direct contact condenser configuration increases energy efficiency and reduces capital costs.

[0007] The system may include a stripper column. The stripper column may include a first packing section and a first inlet. The system may additionally include a second packing section. The system may also include a bypass inlet configured to deliver a fluid to an upper portion of the second packing section. The system may further include a first heat exchanger. The first heat exchanger may include a first inlet and a first outlet. The system may additionally include a first flow path from the first heat exchanger to the stripper column. The first flow path may include a first outlet of the first heat exchanger and a first inlet of the stripper column. The system may also include a second flow path from a location upstream of the first inlet of the first heat exchanger to the bypass inlet.

[0008] The method may include flowing a first portion of the first stream into an upper portion of the first packing section. The first portion of the first stream is at a first temperature. The first stream may include a component. The first stream is a first liquid stream at the first temperature. The method may additionally include flowing a second portion of the first stream into a first inlet of the stripper column. The second portion of the first stream is at a second temperature. The second temperature is higher than the first temperature. The first inlet is below an upper portion of the first packing section. The method may also include flowing a third portion of the first stream into a second inlet of the stripper column. The third portion of the first stream is at a third temperature. The third temperature is higher than the second temperature. The second inlet is below the first inlet. The third portion of the first stream is a first vapor stream at the third temperature. The method may further include flowing the first vapor stream through the stripper column, through the first packing section, and upward. The method may additionally include passing the first liquid stream through a first packing section and downwardly through a stripper column. The method may also include transferring components from the first liquid stream to a first vapor stream. The method may further include separating the components by condensing the first vapor stream with a second liquid stream to obtain a second vapor stream that may include the components.

[0009] The system may include a stripper column. The stripper column may include a first tray section and a first inlet. The system may additionally include a second tray section. The system may also include a bypass inlet configured to deliver a fluid to an upper portion of the second tray section. The system may further include a first heat exchanger. The first heat exchanger may include a first inlet and a first outlet. The system may additionally include a first flow path from the first heat exchanger to the stripper column. The first flow path may include a first outlet of the first heat exchanger and a first inlet of the stripper column. The system may also include a second flow path from a location upstream of the first inlet of the first heat exchanger to the bypass inlet.

[0010] The method may include flowing a first portion of the first stream into an upper portion of the first tray section. The first portion of the first stream is at a first temperature. The first stream may include a component. The first stream is a first liquid stream at the first temperature. The method may additionally include flowing a second portion of the first stream into a first inlet of the stripper column. The second portion of the first stream is at a second temperature. The second temperature is higher than the first temperature. The first inlet is below the upper portion of the first tray section. The method may also include flowing a third portion of the first stream into a second inlet of the stripper column. The third portion of the first stream is at a third temperature. The third temperature is higher than the second temperature. The second inlet is below the first inlet. The third portion of the first stream is a first vapor stream at the third temperature. The method may further include flowing the first vapor stream through the stripper column and upward through the first tray section. The method may additionally include passing the first liquid stream through a first tray section and downwardly through a stripper column. The method may also include transferring components from the first liquid stream to a first vapor stream. The method may further include separating the components by condensing the first vapor stream with a second liquid stream to obtain a second vapor stream that may include the components.

[0011] Without being bound by any particular theory, the present specification may discuss a belief or understanding of the underlying principles related to the present invention. It is recognized that regardless of whether any mechanistic explanation or hypothesis is ultimately correct, embodiments of the present invention may nevertheless be operable and useful. [Brief explanation of the drawings]

[0012] [Figure 1] The base case design of Piperazine with the Advanced Stripper (PZAS) is shown. [Figure 2] 1 illustrates a system for separation using a direct contact condenser according to an embodiment of the present invention. [Figure 3] 1 is a flowchart of a process for separating components from a stream in accordance with an embodiment of the present invention. [Figure 4] FIG. 1 shows a base case process flow diagram using a direct contact condenser instead of a CO2 exchanger according to an embodiment of the invention. [Figure 5] 1 shows a graph of heat duty versus fill height in a direct contact condenser according to an embodiment of the present invention. [Figure 6] 1 shows a graph of rich load versus packing height in a cold rich bypass exiting a direct contact condenser in a direct contact condenser in accordance with an embodiment of the present invention. [Figure 7] 1 shows a graph of the temperature and flow profile in a stripper column according to an embodiment of the present invention. [Figure 8] 10 shows a graph of reduced gas temperature exiting a direct contact condenser compared to a base case in accordance with an embodiment of the present invention. [Figure 9] 4 shows a graph of condenser load versus packing height in accordance with an embodiment of the present invention. [Figure 10] 1 illustrates different equipment costs and packing heights according to an embodiment of the present invention. [Figure 11] 10 is a graph of annual operating cost and purchased equipment cost sensitivity according to an embodiment of the present invention. [Figure 12] FIG. 1 shows a process flow diagram for the base case with double the number of cross-exchangers, using direct contact condensers instead of CO2 exchangers, in accordance with an embodiment of the present invention. [Figure 13] 1 shows a graph of heat duty versus fill height in a direct contact condenser according to an embodiment of the present invention. [Figure 14] 1 shows a graph of rich load versus packing height in a cold rich bypass exiting a direct contact condenser in a direct contact condenser in accordance with an embodiment of the present invention. [Figure 15] 1 shows a graph of the temperature and flow profile in a stripper column according to an embodiment of the present invention. [Figure 16]10 shows a graph of reduced gas temperature exiting a direct contact condenser compared to a base case in accordance with an embodiment of the present invention. [Figure 17] 4 shows a graph of condenser load versus packing height in accordance with an embodiment of the present invention. [Figure 18] 1 illustrates different equipment costs and packing heights according to an embodiment of the present invention. [Figure 19] 10 is a graph of annual operating cost and annualized purchased equipment cost sensitivity according to an embodiment of the present invention. [Figure 20] 1 illustrates total capture cost versus fill height according to an embodiment of the present invention. [Figure 21] 1 illustrates the effect of total rich bypass on the heat load and residual condenser load downstream of the direct contact condenser for Scenario 1, in accordance with an embodiment of the present invention. [Figure 22] 10 illustrates the impact of total rich bypass on the heat load and residual condenser load downstream of the direct contact condenser for Scenario 2, in accordance with an embodiment of the present invention. [Figure 23] 10 illustrates the effect of using different total rich bypasses on heat load for Scenario 1, in accordance with an embodiment of the present invention. [Figure 24] 10 illustrates the effect of using different total rich bypasses on the gas temperature exiting the direct contact condenser for Scenario 1, in accordance with an embodiment of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0013] The additional packing or tray section above the stripper replaces the CO2 exchanger (i.e., the heat exchanger that uses the CO2 and steam stream to heat the cold-rich bypass stream), a major cost-bearing component, with an additional packing or tray section above the stripper that functions as a direct-contact condenser. The scenario demonstrates that replacing the CO2 exchanger with a direct-contact condenser reduces the heat load in the steam heater and boiler through the additional stripping provided by the additional packing or tray section. The scenario also demonstrates additional cooling of the gas exiting the slipper compared to the base case. The condenser and knock-out (KO) drum may be eliminated. These benefits may include reduced capital costs for the boiler, steam heater, condenser, KO drum, and air cooler for water wash in the absorber.

[0014] Additional packing or tray sections in the stripper may reduce capital costs in scenarios involving high temperature (e.g., above 130°C) and / or high pressure (e.g., above 2.5 bar) solvents. With low temperature and / or low pressure solvents, the stripper column may be larger in diameter. At these larger diameters, additional packing sections may result in higher capital costs than using a heat exchanger. Additionally, one skilled in the art would not understand the benefits of using additional packing or tray sections without proceeding with an analysis similar to that described herein. Thus, one skilled in the art would not have been motivated to replace a heat exchanger with additional packing or tray sections.

[0015] Generally, the terms and phrases used herein have their art-recognized meanings which can be found by reference to standard texts, reference journals, and contexts known to those of ordinary skill in the art. The following definitions are provided to clarify their specific use in the context of this disclosure.

[0016] "Stripper" or "stripper column" refers to a vessel in which the physical separation process of stripping occurs. Stripping involves removing components from a liquid stream with a vapor stream. Stripping may be carried out in a packed column or a tray column. A packed column increases the contact area between the liquid and vapor phases. Different types of packing may be commercially available.

[0017] "Fluid communication" may refer to the relationship of two locations to one another such that a fluid (e.g., a liquid or gas) can flow from one location to the other with little or no obstruction (e.g., without passing through a reactor or separation unit operation). In addition, two locations may be in fluid communication if a fluid can occupy a path between the two locations and waves propagating through the fluid at one location can travel to the other location.

[0018] A "flow path" may refer to conveyance from one location to another. For example, a flow path may include a pipe configured to deliver a fluid from one location to another. A flow path may be direct or indirect. An indirect flow path may pass through different unit operations (e.g., reactors) from one location to another.

[0019] I. Introduction Several authors have investigated advanced stripper configurations that potentially reduce the energy requirements for CO2 stripping compared to simple stripper processes [1]-

[12] . Unlike previous efforts, this disclosure involves an advanced stripping process via a combination of a cold rich bypass, a warm rich bypass, and an advanced solvent (5 molar piperazine [PZ]) operating at high pressure (e.g., 5 bar) and high temperature in the stripper. This is an improvement over the Piperazine with the Advanced Stripper (PZAS) system. The cold rich bypass is sent directly to a packed direct-contact condenser at the top of the stripper tower, replacing the CO2 exchanger. The cold rich bypass condenses the steam exiting the stripper while also allowing for some additional stripping in the high-temperature zone, further cooling the gas before the solvent enters the stripper tower and reducing the rich load. In this direct contact condenser, the cold rich bypass is preheated using steam exiting the stripper and mixed with another warm rich bypass withdrawn between the cold and heat cross exchangers. The total rich bypass is then sent to the top of the stripper column, which operates at high pressure and temperature using 5m PZ as the solvent.

[0020] The Piperazine with the Advanced Stripper (PZAS) process was developed at the University of Texas at Austin. Wetted-wall experiments established that 5 m PZ absorbs CO2 two to three times faster than monoethanolamine (MEA).

[13] The measured amine vapor pressure of 5 m loaded PZ is significantly lower than that of 7 m loaded MEA.

[14] At 163 °C, aqueous PZ decomposes at the same rate as MEA at 121 °C. [15, 16] Aqueous PZ does not oxidize at absorber conditions, but can have a significant rate of oxidative decomposition when cycled to 150 °C.

[17] The corrosive properties of PZ allow the use of carbon steel at absorber conditions, although 304 SS can be used at higher stripper temperatures (150 °C).

[18] Process thermodynamics and absorption kinetics are accurately characterized in Aspen Plus® through rigorous rate-based modeling using the Independence™ thermodynamic model.

[19] Several pilot plant campaigns have demonstrated the performance and reliability of the PZAS process. It was demonstrated at the Austin Separations Research Program (SRP) at the University of Texas at Austin in four campaigns from 2010 to 2018 under coal conditions (12% CO2 in air). In 2018, a 2000-hour operation on 0.5 MW coal-fired flue gas at the National Carbon Capture Center (NCCC) validated the process model and confirmed low levels of solvent oxidation. The process was tested at 4% CO2 in two campaigns at SRP in 2017 and 2018. A 1000-hour operation at SRP in 2022 demonstrated that NO2 may play a major role in solvent oxidation

[20] . Further details can be found in patents by Rochelle et al. [21, 22], the entire contents of which are incorporated herein by reference.

[0021] Figure 1 shows the design of the regeneration section of a CO2 capture unit with a PZAS system. This design includes two parallel CO2 absorption / solvent regeneration trains, followed by dedicated CO2 compression and dehydration units for each individual train. In each train, flue gas from the stack travels through an induced draft fan and combines with flue gas from the gas boiler before entering the bottom of the absorber. The flue gas countercurrently contacts 5 m of piperazine (PZ) (30 wt%) to remove 90% of the CO2. Wash water in the upper layer of the absorber removes PZ vapor from the gas before it exits the stack at the top of the absorber. An absorber intercooler controls the solvent temperature by removing enthalpy from the hot incoming flue gas and the heat of CO2 absorption at the bottom of the column. The rich solvent stream 104 exiting the absorber flows through a series of heat exchangers 108 and 112 before entering a pressurized stripper 116. The cold rich bypass 120 exchanges heat with the gas 124 exiting the stripper in a CO2 exchanger 128. The cold rich bypass 120 and the warm rich bypass 132 are combined and then enter the stripper, further cooling the CO2 as it exits the stripper. The lean solvent 136 returns to the absorber through a solvent heat exchanger. A small percentage of the lean solvent is sent to a recovery vessel to remove cracking products and return clean solvent. The product CO2 is cooled in a CO2 cooler, pressurized in a CO2 compressor, and then sent to a CO2 pipeline. Water condensed from the CO2 stream through a condenser 140 is removed in a knockout drum and sent to a wash water storage tank. The stream produced from the gas boiler is used to heat the rich solvent in a steam heater. Further details can be found in a patent by Rochelle et al.

[23] , the entire contents of which are incorporated herein by reference.

[0022] The base-case stripper design includes a high-pressure stripper operating at 5.5 bar with a bottom temperature of 150°C. The stripper contains two sections of random packing, with a total packing height of 7.4 m and a diameter of 3.4 m. The top section contains RSR2 packing, and the bottom section contains RSR3 packing. High-pressure and high-temperature stripping, combined with a heat exchanger network, reduces the stripping energy requirements and also reduces downstream condenser service requirements. The cold cross exchanger was designed with a total of 1.7 NTU heat cross exchanger and 3.8 NTU CO2 exchanger, for a total of 5.3 NTU (number of heat transfer units). The use of cold and warm rich bypasses in the process helps reduce the energy requirements of the process. The use of a combination of two bypasses in the base case allows nearly 70% of the solvent to be bypassed to the stripper overhead. The cold bypass recovers latent heat from the steam exiting the stripper in the CO2 exchanger and eliminates cold-side heat exchanger pinch in the cold cross exchanger. When advantageously combined with the warm rich bypass, solvent bypassed to the top of the stripper can also eliminate any pinch in the stripper column, making stripper operation more reliable. Detailed design specifications for the stripper section are provided by Suresh Babu and Rochelle

[24] and Closmann et al.

[25] .

[0023] II. Systems with direct contact condensers This document includes an improvement over the base case of the PZAS process, whereby the CO2 exchanger is eliminated and replaced with an additional packing section at the top of the stripper column. The additional packing section, unlike the CO2 exchanger, may condense steam exiting the second packing section in the stripper using a cold rich bypass via direct contact. This improvement provides several benefits.

[0024] The retrofit could eliminate the capital costs associated with the CO2 exchanger. Being a gas-liquid shell-and-tube exchanger, the CO2 exchanger was the most expensive cross-exchanger in the base case. Details on the cost breakdown for the base case are provided by Rochelle et al.

[26] .

[0025] The additional packing section above the stripper provides the opportunity to use a cold rich bypass to further cool the steam exiting the stripper, which may partially or completely eliminate the downstream condenser and knockout drum, reducing the CAPEX (capital expenditure) of the process.

[0026] An additional packing section at the top of the stripper may allow for some further stripping of solvent due to the higher temperature in the bottom section, which may further reduce the energy requirements of the process compared to the base case energy requirements, thereby reducing OPEX (operating expenditures).

[0027] The reduced energy requirements may reduce the overall CAPEX of the plant through reduced size (and cost) of new steam heaters, isolated gas-fired boilers, water wash area air coolers, condensers, and KO drums.

[0028] This improvement can reduce the footprint associated with the CO exchanger, condenser, and knockout drum by vertically integrating these operations with an additional packing section above the stripper, which can be particularly useful when the PZAS process is used in space-constrained locations.

[0029] When used at elevated pressures (3-10 bar) with a stripper, capital costs for additional packing sections are minimized or reduced, which may involve solvents that are resistant to thermal decomposition, such as aqueous piperazine.

[0030] A. Exemplary System FIG. 2 shows a system 200 for separation. System 200 may include a stripper column 204. Stripper column 204 may include a first packing section 208 and a first inlet 210. First inlet 210 may be at the top of first packing section 208. System 200 may additionally include a second packing section 212. Second packing section 212 may have a height in the range of 5 feet to 10 feet, 10 feet to 15 feet, 15 feet to 20 feet, or 20 feet to 30 feet. Second packing section 212 may be referred to as a direct contact condenser.

[0031] 2, stripper column 204 may include a third packing section 296. First packing section 208, second packing section 212, and third packing section 296 may each be individually and independently random packing or structured packing. In some embodiments, trays may be used instead of packing.

[0032] The system 200 may also include a bypass inlet 216 configured to deliver fluid to an upper portion of the second packing section 212. The system 200 may further include a first heat exchanger 220. The first heat exchanger 220 may include a first inlet 224 and a first outlet 228. The system 200 may additionally include a first flow path 232 from the first heat exchanger 220 to the stripper column 204. The first flow path 232 may be a warm-rich bypass. The first flow path 232 may include the first outlet 228 of the first heat exchanger 220 and the first inlet 210 of the stripper column 204. The system 200 may also include a second flow path 236 from a location upstream of the first inlet 224 of the first heat exchanger 220 to the bypass inlet 216.

[0033] Stripper column 204 may include a second packing section 212. Stripper column 204 may have a diameter ranging from 2 feet to 5 feet, 5 feet to 10 feet, 10 feet to 15 feet, 15 feet to 20 feet, or 20 feet to 30 feet. The total packing in stripper column 204 may have a height ranging from 10 feet to 15 feet, 15 feet to 20 feet, 20 feet to 30 feet, 30 feet to 35 feet, 35 feet to 45 feet, 45 feet to 50 feet, or 50 feet to 60 feet. The amount of packing in second packing section 212 may be in the range of 10% to 20%, 20% to 25%, 25% to 30%, 30% to 35%, 35% to 40%, 40% to 45%, 45% to 50%, or 50% to 55% of the total amount of packing in stripper column 204 (and including second packing section 212 if second packing section 212 is not within stripper column 204). These amounts for trays may be similar to the amounts for packing. In FIG. 2, when stripper column 204 includes second packing section 212, streams 292 and 294 may be within stripper column 204. Stripper column 204 may be 80 to 90 feet, 90 to 100 feet, 100 to 110 feet, 110 to 120 feet, or greater than 120 feet in height.

[0034] In some embodiments, stripper column 204 may not include second packing section 212. Second packing section 212 may be in a separate vessel. Thus, the separate vessel may have a different diameter and / or height than stripper column 204. The separate vessel may have a diameter ranging from 5 feet to 10 feet, 10 feet to 15 feet, 15 feet to 20 feet, or 20 feet to 30 feet. The separate vessel may have a height ranging from 5 feet to 10 feet, 10 feet to 15 feet, 15 feet to 20 feet, or 20 feet to 30 feet. In FIG. 2, when stripper column 204 does not include second packing section 212, streams 292 and 294 may be external to stripper column 204.

[0035] The stripper column 204 may include a bypass inlet 216. The stripper column 204 may include a second outlet 282. The system 200 may include a condenser 284. The condenser 284 may include an inlet 286. The inlet 286 of the condenser 284 may be in fluid communication with the second outlet 282 of the stripper column 204.

[0036] The system 200 may include a second heat exchanger 240. The second heat exchanger 240 may include a first inlet 244 and a first outlet 248. The first outlet 228 of the first heat exchanger 220 may be in fluid communication with the first inlet 244 of the second heat exchanger 240. The stripper column 204 may further include a second inlet 252. The system 200 may include a third flow path 256. The third flow path 256 may include the first outlet 248 of the second heat exchanger 240 and the second inlet 252 of the stripper column 204.

[0037] The first heat exchanger 220 may include a second inlet 260 and a second outlet 264. The second heat exchanger 240 may include a second inlet 268 and a second outlet 272. The stripper column 204 may include a first outlet 276. The first outlet 276 of the stripper column 204 may be in fluid communication with the second inlet 268 of the second heat exchanger 240. The second outlet 272 of the second heat exchanger 240 may be in fluid communication with the second inlet 260 of the first heat exchanger 220.

[0038] The system 200 may include a heater 280. The heater 280 may be configured to heat a fluid between the first outlet 248 of the second heat exchanger 240 and the second inlet 252 of the stripper column 204. The heater 280 may be a convection steam heater.

[0039] System 200 may include an absorber. The absorber may include an inlet and an outlet. System 200 may include a recycle flow path 288. The outlet of the absorber may be in fluid communication with the first inlet 224 of the first heat exchanger 220. The recycle flow path 288 may include the first outlet 276 of the stripper column 204 and the inlet of the absorber. Although the absorber is not shown in FIG. 2 , the absorber may be connected to the recycle flow path 288 and an absorber outlet stream 290.

[0040] The system 200 may exclude heat exchangers used to capture heat from the stripper overhead gas stream. The system 200 may exclude gas-liquid shell-and-tube heat exchangers. For example, the system 200 may exclude the CO2 exchanger 128.

[0041] The system may include a fluid. The fluid may include an aqueous solution of an amine. Examples of suitable solvents include, but are not limited to, aqueous solutions of monoethanolamine (MEA), piperazine (PZ), or other amines. More specifically, the solvent may be an aqueous blend of piperazine or other reactive amines with tertiary or hindered amines that do not form carbamates, such as piperazine / methyldiethanolamine, piperazine / 2-aminopropanolamine, 2-methylpiperazine, and piperazine / 2-piperidine-ethanol. The solvent may include primary or secondary amines, such as diglycolamine and diethanolamine. The solvent may use an enzyme or other catalyst to enhance CO2 absorption rate, such as methyldiethanolamine with one or more enzymes. The solvent may also be a blend of piperazine and other heat-stable amines, such as piperazine / aminoethylpiperazine and piperazine / 2-methylpiperazine. The solvent may also be an ionic liquid containing amine functionality.

[0042] B. Exemplary Methods 3 is a flow chart of an example process 300 for separating a component from a stream. In some implementations, one or more process blocks of FIG. 3 may be performed by system 200. The component may be carbon dioxide or other acid gas, such as hydrogen sulfide or sulfur dioxide.

[0043] At block 310, the process 300 may include flowing a first portion of the first stream into an upper portion of a first packing section. The first portion may be 5%-10%, 10%-15%, 15%-20%, or 20%-25% of the first stream. The first portion of the first stream may be at a first temperature. The first temperature may be 30-35°C, 35-40°C, 40-45°C, 45-50°C, or 50-60°C. The first stream may include a component. The first stream may be a first liquid stream at a first temperature. The first packing section may be in a stripper column. The first portion of the first stream may correspond to the second flow path 236. The first packing section in the process 300 may correspond to the second packing section 212. The stripper column may correspond to the stripper column 204. As described for system 200, trays may be used in place of packing, and therefore process 300 may be performed substituting trays for any reference to packing.

[0044] Process 300 may further include flowing a first stream from the absorber. The component may be carbon dioxide. The solvent may include water and an amine, including any amine described herein. The first stream may have a first loading of 0.4 moles of carbon dioxide or more per mole of nitrogen. For example, the first loading may be 0.4 to 0.5, 0.5 to 0.6, or 0.6 to 0.7. The first stream may correspond to absorber outlet stream 290.

[0045] At block 320, the process 300 may include flowing a second portion of the first stream to a first inlet of the stripper column. The second portion may be 20%-30%, 30%-40%, 40%-45%, 45%-50%, 50%-55%, or 55%-60% of the first stream. The second portion of the first stream may be at a second temperature. The second temperature may be higher than the first temperature. The second temperature may be 100-110°C, 110-120°C, 120-130°C, or 130-140°C. The first inlet may be below the top of the first packing section. The first inlet may be first inlet 210. The second portion of the first stream may be first flow path 232.

[0046] At block 330, the process 300 may include flowing a third portion of the first stream to a second inlet of the stripper column. The third portion may be 20%-25%, 25%-30%, 30%-35%, 35%-40%, 40%-50%, 50%-60%, or 60%-70% of the first stream. The first, second, and third portions may be the entire first stream. The third portion of the first stream may be at a third temperature. The third temperature may be higher than the second temperature. The third temperature may be at least 130°C, including 130-140°C, 140-150°C, 150-160°C, 160-170°C, 170-180°C, or greater than 180°C. The process 300 may include heating the third portion of the first stream to the third temperature using a steam heater. The second inlet may be below the first inlet. The third portion of the first stream may be a first vapor stream at a third temperature. The third portion of the first stream may be at a pressure of at least 2.5 bar, including 2.5 to 3.0 bar, 3.0 to 3.5 bar, or greater than 3.5 bar. The second inlet may be second inlet 252. The third portion may correspond to third flow path 256.

[0047] At block 340, process 300 may include flowing vapor through the stripper column, through the first packing section, and up. For example, flowing the first vapor stream may include flowing the first vapor stream into stream 292.

[0048] At block 350, process 300 may include flowing the first liquid stream down through a first packing section and through a stripper column. For example, flowing the first liquid stream down may include flowing the liquid stream into stream 294.

[0049] At block 360, the process 300 may include transferring a component from the first liquid stream to the first vapor stream. The transferring of the component may be the result of mass transfer occurring within the stripper column.

[0050] At block 370, process 300 may include separating the components by condensing the first vapor stream into a second liquid stream to obtain a second vapor stream that may include the components. Condensing the vapor stream may be in a condenser. The stripper column may not include a condenser. In some embodiments, a condenser for this condensing step may not exist outside of the stripper column. The condenser may be condenser 284. The second liquid stream may be the water stream of FIG. 2. The second vapor stream may be the CO2 stream of FIG. 2.

[0051] The first stream may comprise the constituent element in a first proportion. The first proportion may be a mass fraction of 0.20-0.30, 0.25-0.30, 0.30-0.35, 0.35-0.40, or 0.40-0.50. Process 300 may further include flowing the bottoms stream through a first outlet of the stripper column. The bottoms stream may comprise the constituent element in a second proportion. The second proportion may be less than the first proportion. The second proportion may be a mass fraction of 0.01-0.05, 0.05-0.10, 0.10-0.15, 0.15-0.20, or 0.20-0.25. The second rate may be reduced by 25% to 30%, 30% to 40%, 40%, 50% to 60%, 60% to 75%, or more than 75% compared to the first rate. Process 300 may further include cooling the bottoms stream with a second portion of the first stream. Cooling the bottoms stream may further include cooling the bottoms stream with a third portion of the first stream. For example, the first outlet may be first outlet 276. Heating and cooling of the streams may be by using heat exchangers, such as first heat exchanger 220 and second heat exchanger 240.

[0052] Process 300 may further include flowing the bottoms stream to an absorber. The bottoms stream may have a second load of 0.2 or less. For example, the second load may be 0.15 to 0.20, 0.10 to 0.15, or 0.05 to 0.10. The load in the bottoms stream may be reduced by 25% to 30%, 30% to 40%, 40%, to 50%, 50% to 60%, 60% to 75%, or more than 75% compared to the first stream.

[0053] Process 300 may include additional implementations, e.g., any single implementation or any combination of implementations described and / or in conjunction with one or more other processes described elsewhere herein.

[0054] 3 illustrates example blocks of process 300, in some implementations, process 300 may include additional blocks, fewer blocks, different blocks, or blocks arranged differently than depicted in FIG 3. Additionally or alternatively, two or more of the blocks of process 300 may be performed in parallel. III. [Example]

[0055] Embodiments of the present invention can be further understood by the following non-limiting examples. Two scenarios with different heat transfer units and pressure drops in the cold and hot cross exchangers were evaluated for their benefits, process tradeoffs, and economics in this substitution. Both scenarios demonstrated that replacing the CO2 exchanger with a direct contact condenser can reduce the heat load in the steam heater and boiler through additional stripping in the third packing section, albeit with some reabsorption in the lower temperature region. Both scenarios also demonstrated additional cooling of the gas exiting the stripper compared to the base case; in Scenario 2, the higher cold-rich bypass brings the gas exiting the stripper closer to equilibrium with the liquid entering the stripper, nearly eliminating the need for a condenser and knock-out (KO) drum. These benefits translate into reduced capital costs for the boiler, steam heater, condenser, and KO drum.

[0056] A. Modeling Method Modeling of the PZAS for the base case and proposed improvements was performed in Aspen Plus®. A rate-based modeling approach was used, using the Song mass transfer model

[27] for mass transfer coefficients and the wetted area of ​​the packing in the packed column, and the Independence™ thermodynamic model

[28] to describe the vapor-liquid equilibrium, physical properties, and rate behavior of 5m piperazine. The bottom two sections of the stripper column were modeled using equilibrium kinetics at high temperatures and with an empirical correction of 0.16 applied to the wetted area of ​​the packing

[29] . A new third packing section at the top of the stripper was modeled differently, using kinetic kinetics at lower temperatures and with no correction applied to the wetted area

[30] . This packing section functions partially as an absorber in the low temperature region and as a stripper in the high temperature region, making a single wetted area correction factor inaccurate. A design model was used to evaluate the base-case performance of the process, and a rate model was used to more accurately model all other scenarios presented in this document. Suresh Babu et al.

[31] provide a detailed description of the design and rate model. The combination of the design and rate model is used to test the hypotheses of this study. For the scenario with double the number of cross exchangers, the cold lean pump was replaced with a hot lean pump upstream of the heat cross exchanger and downstream of the stripper sump to compensate for the increased pressure drop and avoid cavitation. Pump power was estimated for this case in design mode with a specified pressure increase based on the positional head in the lean line entering the absorber and a pump efficiency of 65%.

[0057] B. Cost scaling and economic evaluation methods For cost scaling purposes, the purchased equipment costs (PECs) of the following units were considered using the base-case costs as a reference point: cold cross exchanger, heat cross exchanger, CO2 exchanger, steam heater, rich and lean solvent pumps, intercooler pumps in the absorber, intercooler air cooler for the absorber, package boiler, CO2 compressor, CO2 condenser and knockout drum, stripper vessel (charge and other contents), and air cooler for the water wash. The total direct field cost (DFC) of all equipment in the base-case test was $384.1 mm, which was converted to a PEC of $760.5 mm using a factor of 1.98. In the evaluation of the new designs presented in this document, the costs of the above equipment are expected to change due to changes in process variables, including steam heater load, boiler heat load, heat exchanger pressure drop, and condenser load. The costs of the absorber intercooler air cooler and pumps are not expected to change with these new configurations and were therefore held constant. For the other costs, we used a simple power law scaling with a factor of 0.6, as shown below.

number

[0058] The table below shows the base case DFC and scaling variables used for each piece of equipment. [Table 1]

[0059] To convert PECs to annualized PECs, the total direct costs were first multiplied by a scaling factor, α, and then by an annualization factor, β. The scaling factor includes direct and indirect installation costs, contingencies, construction costs, and ancillary facilities. The annualization factor considers capital yields, taxes, depreciation, and maintenance. In this study, α was chosen to be 1.98, and β was chosen to be 0.2. The annualized PECs may then be normalized by the total CO2 flow per year according to the following formula:

number

[0060] In addition to the PEC, annualized operating costs were projected for the two scenarios developed in this study. To do so, gas prices were assumed to be $3 / MMBtu and electricity prices were assumed to be $25 / MWh. The heat generation rate of the natural gas-fired boiler constituted the major portion of the heating costs. Rich and lean pumping requirements were varied in the two scenarios, which explains the different electricity costs. In addition to the solvent pumps, there were other areas of the process that required electricity, such as air coolers and intercooler pumps. The power requirements of these components were not expected to change in the scenarios presented in this paper, so they were fixed at the base-case value. Compressor power was projected based on a proxy model provided by Suresh Babu et al.

[26] . A 52% capacity factor was used for all cost calculation methods used. The annualized PEC and annualized operating costs were combined to project the total cost of CO2 capture.

[0061] C. Scenario 1: Base case using a direct contact condenser instead of a CO2 exchanger The first scenario considers replacing the CO2 exchanger with a packed direct-contact condenser at the top of the stripper tower, while keeping the number and size of the cold and heat cross exchangers the same as in the base case design. A sensitivity analysis was performed by varying the packing height in the direct-contact condenser to observe the impact on steam heater load, condenser load, gas temperature, rich load, and equipment costs compared to the base case design. Tradeoffs and benefits are highlighted. In this scenario, the cold and heat cross exchangers have the same pressure drop as the base case design, so the rich and lean pumps have similar power requirements as the base case design. The cold and warm rich bypass flow rates were specified to be the same as the advantageous values ​​for the base case design to individually highlight the impact of replacing the CO2 exchanger with a direct-contact condenser. Figure 4 shows the process flow diagram for this case.

[0062] The packing height in the direct contact condenser was increased from 2 ft to 30 ft. The packing type used was RSR2. Below 5 ft of packing, the direct contact condenser underperformed compared to the CO2 exchanger. The heat load was higher than the base case heat load of 3 GJ / ton, as shown in Figure 5. Five ft of packing in the direct contact condenser was sufficient to match the base case design heat load. With further increases in packing height, the heat load decreased monotonically, eventually approaching 2.9 GJ / ton.

[0063] With less than 5 ft of packing in the direct contact condenser, the net effect of reabsorption in this packing section dominates stripping, resulting in a higher rich load in the cold rich bypass solvent exiting this section compared to that of the CO2 exchanger. In addition, the temperature of the steam exiting the stripper is higher than the base case due to insufficient packing to allow condensation of water in the stripper. Ultimately, this results in an increased condenser load at 85°F compared to the base case design. The effect of packing height on the rich load in the heated cold rich bypass stream is shown in Figure 6.

[0064] 6 also shows that increasing the packing in the direct contact condenser causes the packed section to function more as a stripper than as an absorber, which is reflected in the reduced rich load on the heated cold rich bypass solvent exiting this packed section compared to that exiting the CO2 exchanger in the base case design. This indicates that even though reabsorption occurs at the cold end of the direct contact condenser, the additional stripping provided by the direct contact condenser at the top of the main stripper tower may result in lower heat duty, gas temperature, and ultimately condenser load compared to the base case design.

[0065] The stripper liquid and vapor temperature profiles for a direct contact condenser with a total packing height of 12.3 ft are shown in Figure 7, which represents three symmetrically packed sections on top of each other in the stripper column. The diameter of the direct contact condenser was equal to the diameter of the stripper column. Stage 1 is the top of the column and stage 35 is the bottom of the column. The total packing height in the direct contact condenser is 12.3 ft. Negative CO2 flow indicates stripping. The lean load (lldg) is 0.2 mol / mol. The rich load (rldg) is 0.4 mol / mol. The cold rich bypass split percentage is 15.2%. The warm rich bypass split percentage is 52% (e.g., the second portion in process 300). Figure 7 shows that the direct contact condenser provides additional stripping.

[0066] Figure 8 shows that as the packing height increases above about 5 ft, the gas temperature exiting the direct contact condenser can be reduced below the gas temperature exiting the CO2 exchanger with the same flow of cold rich bypass through these units. The direct contact condenser allows for additional stripping of CO2 and cooling of the gas via the condensate. This reduces the condenser load as shown in Figure 9, which indicates that the condenser and knockout drum can be partially or completely eliminated by using a direct contact condenser rather than a CO2 exchanger.

[0067] Figure 9 shows that the additional cooling of the gas in the direct contact condenser reduces the downstream condenser load at increased packing heights. This may mean that scaling the base case costs with the condenser load results in lower condenser and KO drum costs. At a packing height of about 30 ft, the condenser load is only 2 MW for a base case load of about 10 MW, indicating that the condenser could be eliminated from the design entirely, although this may not be economically optimal considering that the cost of the stripper packing and contents may be greatest at such a high packing height.

[0068] Figure 10 shows the predicted direct field costs (DFCs) for the boiler, steam heater, condenser, and KO drum, as well as the stripper tower, using the scaling methodology described above. Figure 10 shows that the use of a direct contact condenser can reduce the costs of the boiler, steam heater, condenser, and KO drum. Three major cost accounting sections are shown that showed significant reductions in direct field costs. The reduction in boiler and steam heater costs can be attributed to the reduced heat duty caused by increasing the packing height in the direct contact condenser relative to the base case design. The reduction in condenser and KO drum costs can be attributed to the reduced condenser load caused by increasing the packing height in the direct contact condenser. At very high packing heights, the condenser and KO drum costs approach $1MM. The increase in stripper tower cost can be attributed to the increased shell surface and increased packing area caused by the additional direct contact condenser.

[0069] The cost details at 0 ft packing height were scaled from the base case design using the heat duty, boiler heat rate, and condenser duty extrapolated from the curves shown in the previous figure. At 0 ft packing height in the stripper, the additional cost of the stripper is associated with the stripper shell and contents, not the additional packing compared to the base case. The costs of other equipment, such as pumps and CO2 compressors, did not change significantly due to the very similar pressure drop and CO2 flow rate through the exchangers in this design compared to the base case design.

[0070] Figure 11 shows how annualized PEC and operating costs vary as packing height increases in a direct contact condenser. As packing height increases, annualized operating costs plateau above 15 ft of packing due to the heat duty remaining nearly constant at higher packing heights. Heat duty is the only variable that varies with packing height; power remains nearly constant. Because most equipment costs scale with heat duty, annualized PEC decreases up to 15 ft, but above 15 ft of packing, the cost of additional packing and contents in the column outpaces this reduction. This may result in a minimum total cost just per 15 ft; this height may be unlikely to vary with gas or electricity prices, but may vary with other variables such as the type of packing in the stripper, the CO2 content in the flue gas, or the stripper pressure.

[0071] D. Scenario 2: Base case with double the number of cross-exchangers using direct contact condensers This scenario evaluates the economics of the base case using double the number of cross exchangers or double the heat transfer units in the cross exchangers and a direct contact condenser instead of a CO2 exchanger, and performs a sensitivity analysis. The modeling and economic methods used are the same as before. The lean pump cost and performance are not expected to change under this scenario because it is a fixed-speed pump that outputs a given pressure for a given liquid flow. The lean pump may need to be located downstream of the stripper sump and before the high-temperature exchanger. The pressure drop on the cold and hot sides of the cross exchanger doubles due to the doubling of the path length for the same flow. After modifying the pressure drop of the base-case design, the bypass was retuned and the configuration was evaluated using a rate model. The lean pump should be located upstream of all cross exchangers, since a location downstream of the heat exchanger could cause cavitation under certain operating conditions due to the large pressure drop in this case. Figure 12 shows the process flow diagram for this case.

[0072] Figure 13 shows the sensitivity of the steam heater load to the packing height added to the direct-contact condenser, with twice as many cross exchangers as in the PZAS base case. Compared to Scenario 1, the heat load is lower and directly correlates with the increased heat exchange area, but the change in heat load is similar to Scenario 1 compared to doubling the number of cross exchangers and CO2 exchangers. The heat load of the original base case design is still approximately 3 GJ / ton. The cold rich bypass flow is slightly higher than in Scenario 1, resulting in more water condensate and consequently greater cooling of the gas exiting the direct-contact condenser. Figure 14 shows that, as in Scenario 1, with approximately 5 ft of packing in the direct-contact condenser, the net stripping of CO2 within the column is higher than the reabsorption rate, resulting in a lower rich load in the heated cold rich bypass exiting this column section. The base case rich load in the cold rich bypass exiting the CO2 exchanger is still approximately 0.4 mol / mol. The stripper temperature profile for a 12.3 ft packing height in a direct contact condenser is shown in FIG.

[0073] Figure 16 shows that in Scenario 2, the gas temperature exiting the direct contact condenser may be lower than in Scenario 1 at the same packing height in the section, primarily due to the higher amount of cold rich bypass. This independently highlights the impact of cold rich flow through the section. At packing heights of 20 ft or more, the gas temperature exiting the direct contact condenser is approximately 42°C, bringing it to near equilibrium with the cold rich bypass entering the column. In this case, the downstream condenser duty may be close to zero due to the near complete condensation of water in the stripper column. This may further reduce the condenser and KO drum costs in this scenario compared to the base case and Scenario 1, and may nearly eliminate the need for this equipment.

[0074] FIG. 17 shows that as the packing height in the direct contact condenser increases, the condenser load drops, similar to Scenario 1 but slightly lower, due to the higher cold-rich bypass. At very high packing heights, the condenser load can be reduced to nearly zero compared to the base case condenser load of about 10 MW. This nearly eliminates the need for a condenser and KO drum, as seen in FIG. 18. The boiler and steam heater show cost reductions like Scenario 1, but slightly lower due to the lower boiler and steam heater heat loads in Scenario 2. This comes at the expense of additional capital for the shell, contents, and packing in the stripper column, as more packing is added to the direct contact condenser.

[0075] Figure 19 shows how annualized PEC and operating costs vary as packing height increases in a direct contact condenser. Because heat duty is nearly constant at larger packing heights, annualized operating costs level off above 15 ft of packing. Heat duty is the only variable that varies with packing height; power is nearly constant. Because most equipment costs scale with heat duty, annualized PEC decreases up to 15 ft, but above 15 ft, the cost of additional packing and contents in the column offsets this reduction. This may result in a minimum total cost at 15 ft; this height may be unlikely to vary with gas or electricity prices, but may vary with other variables such as the type of packing in the stripper, the CO2 content in the flue gas, or the stripper pressure.

[0076] Figure 20 compares the annualized total costs of Scenario 1 and Scenario 2 with the base case design. First, the figure shows that both scenarios are cheaper than the base case design. This indicates that replacing the base case CO2 exchanger with a direct-contact condenser is always cheaper, regardless of the heat exchanger size and the additional packing height of the direct-contact condenser. The annualized total cost of capture in a direct-contact condenser with a packing height of approximately 15 ft can be up to $4 / ton lower than the base case design. Scenario 2, which doubles the number of cross-exchangers, is cheaper than Scenario 1 regardless of packing height. This is due to lower energy costs due to lower heat loads, despite the additional costs of the heat exchangers and lean pumps. The higher pressure drop through the cross-exchangers increases the head against which the lean pumps are penalized, which increases the lean pump's electrical work from 0.18 MW in the base case design to approximately 0.7 MW in Scenario 2. This increases the cost of the lean pump from approximately $1.2MM to $2.7MM, as predicted by the cost scaling methodology.

[0077] E. Effect of Bypass Flow on the Performance of Direct Contact Condensers The scenarios developed in the previous section were evaluated at favorable bypass flow rates for each case using a CO2 exchanger. This section describes a sensitivity analysis to bypass flow rate, fixing the stripper packing height at a value of 15 ft and looking at its impact on the heat load and the direct-contact condenser. In Figures 21 and 22, the heat load decreases with the use of more total rich bypass. At the extremes, when using very low cold-rich bypass or very low total rich bypass, the heat load is higher than that for the case with 65% to 70% total rich bypass. In this condition, the use of very low cold-rich bypass results in less steam temperature change in the direct-contact condenser because there is less water condensing. This also increases the temperature pinch from the middle to the bottom of the column. In another case using a combination of low cold-rich bypass and high warm-rich bypass, the heat load, although much lower, is still not at its optimal value, but the residual condenser load is still approximately 20 MW. At a particular value of bypass, both the heat load and the condenser load are minimized as shown in Figures 21 and 22. This also shows that using only one of the cold rich bypass and warm rich bypass, rather than using both at values ​​that minimize or reduce the heat load, is likely to result in suboptimal performance for a PZAS with a direct contact condenser.

[0078] From Figures 23 and 24, it appears that the heat duty remains nearly constant at high total rich bypass flow rates. In this section, we investigate whether a 50% total rich bypass fraction (relative to the total rich solvent exiting the absorber) has a similar impact on the heat duty as a 67% total rich bypass fraction. From Figure 23, using a 50% total rich bypass fraction increases the heat duty by an average of about 4.4% as a percentage of the packing height in the direct contact condenser. Importantly, from Figure 24, using a 50% total rich bypass increases not only the gas temperature exiting the packed condenser, but also the downstream residual condenser load. This indicates that using a suboptimal total rich bypass likely results in more expensive steam heaters, isolated gas boilers, CO condensers and KO drums, air coolers for water washes, and natural gas costs. At much lower total rich bypass values, the rich solvent pump may also be poorly designed to handle downstream pressure requirements, especially in Scenario 2, where the pressure drop doubles in the solvent cross-exchanger. This can also increase the cost of the rich solvent pump. Overall, using a suboptimal bypass may not affect the desired packing height in the direct contact condenser, but it will likely increase the total annualized capture cost and reduce the savings gained from using a direct contact condenser instead of a CO2 exchanger.

[0079] F. Scenario Summary The CO2 exchanger in the PZAS base case design was replaced by a packing section above the stripper column that uses a cold rich bypass to condense water vapor in the gas exiting the stripper via direct contact. The two designs were evaluated for their benefits and economics and compared to the base case design. The scenarios varied in the number of cold and hot cross exchanger heat transfer units and their pressure drops.

[0080] The direct field costs of the boiler, steam heater, condenser and KO drum, and stripper tower were primarily affected by substituting a direct contact condenser for the CO2 exchanger through reduced boiler and steam heater loads, additional flue gas cooling, and additional packing costs in the stripper. The direct field costs of this and other equipment were all scaled from the base case design values ​​using appropriate scaling variables.

[0081] Both scenarios reduced the stripping heat duty through additional stripping in the additional packing section, although there was some reabsorption in the cooler packing section.

[0082] Both scenarios provide for additional condensation of water in the third packing section, which reduces the gas temperature exiting the column compared to the base case design. In Scenario 2, the additional cold rich bypass through the packing nearly eliminates the need for a condenser and KO drum, and the gas exiting the stripper approaches equilibrium with the liquid entering the stripper.

[0083] A sensitivity analysis of the base case total annualized PEC as a function of additional packing height in the direct contact condenser showed that at approximately 15 ft packing height, the total annualized capture cost reduction for the two scenarios could be up to $4 / ton of CO2 compared to the base case design.

[0084] Scenario 2, which doubles the heat transfer units in the cross exchanger, shows an increase in lean pumping costs due to the need for a lean pump between the stripper sump and the hot exchanger, which penalizes a larger positional head compared to the cold lean pump in the base case design. This increases the lean pumping workload from 0.18 MW in the base case to 0.7 MW.

[0085] References [1] Bottoms, R.R., 1930. Separating acid gases, Girdler Corp. U.S. Patent No. 1783901. [2] Liu, J., Wong, D.S.H. and Chen, D.S., 2020. Energy-saving performance of advanced stripper configurations for CO2 capture by ammonia-based solvents. Journal of the Taiwan Institute of Chemical Engineers, 113, pp. 273-284. [3] Karimi, M., Hillestad, M. and Svendsen, H.F., 2011. Capital costs and energy considerations of different alternative stripper configurations for post combustion CO2 capture. Chemical engineering research and design, 89(8), pp. 1229-1236. [4] Oh, H.T., Ju, Y., Chung, K. and Lee, C.H., 2020. Techno-economic analysis of advanced stripper configurations for post-combustion CO2 capture amine processes. Energy, 206, p. 118164. [5] Jiang, K., Li, K., Yu, H., Chen, Z., Wardhaugh, L. and Feron, P., 2017. Advancement of ammonia based post-combustion CO2 capture using the advanced flash stripper process. Applied Energy, 202, pp. 496-506. [6]Jung,J.,Jeong,Y.S.,Lim,Y.,Lee,C.S.and Han,C.,2013.Advanced CO2capture process using MEA scrubbing:Configuration of a split flow and phase separation heat exchanger.Energy Procedia,37,pp.1778-1784. [7]Thompson,J.G.,Bhatnagar,S.,Combs,M.,Abad,K.,Onneweer,F.,Pelgen,J.,Link,D.,Figueroa,J.,Nikolic,H.and Liu,K.,2017.Pilot testing of a heat integrated 0.7 MWe CO2capture system with two-stage air-stripping:Amine degradation and metal accumulation.International Journal of Greenhouse Gas Control,64,pp.23-33. [8]Zhao,B.,Liu,F.,Cui,Z.,Liu,C.,Yue,H.,Tang,S.,Liu,Y.,Lu,H.and Liang,B.,2017.Enhancing the energetic efficiency of MDEA / PZ-based CO2capture technology for a 650 MW power plant:Process improvement.Applied energy,185,pp.362-375. [9]Dubois, L. and Thomas, D., 2018. Comparison of various configurations of the absorption-regeneration process using different solvents for the post-combustion CO2 capture applied to cement plant flue gases. International Journal of Greenhouse Gas Control, 69, pp. 20-35.

[10] Li, K., Yu, H., Feron, P., Wardhaugh, L. and Tade, M., 2016. Techno-economic assessment of stripping modifications in an ammonia-based post-combustion capture process. International Journal of Greenhouse Gas Control, 53, pp. 319-327.

[11] Jung, J., Jeong, Y.S., Lee, U., Lim, Y. and Han, C., 2015. New configuration of the CO2 capture process using aqueous monoethanolamine for coal-fired power plants. Industrial & Engineering Chemistry Research, 54(15), pp. 3865-3878.

[12] Rochelle, G.T., University of Texas System, 2011. Regeneration of an aqueous solution from an acid gas absorption process by multistage flashing and stripping. U.S. Patent No. 7,901,487

[13] Dugas RE, CO2 Absorption, Desorption, and Diffusion in Aqueous PZ and MEA. PhD Dissertation, The University of Texas at Austin, 2009.

[14] Nguyen T. Amine Volatility in CO2 Capture. PhD Dissertation, The University of Texas at Austin, 2013.

[15] Freeman SA. Thermal Degradation and Oxidation of Aqueous PZ for CO2 Capture. PhD Dissertation, The University of Texas at Austin, 2011.

[16] Rochelle, G., Du, Y. and Namjoshi, O., University of Texas System, 2017. Thermally stable amines for CO2 capture. U.S. Patent Application No. 15 / 367,404

[17] Wu Y. Mitigation of Piperazine Oxidation in Carbon Dioxide Capture by Amine Scrubbing. PhD Dissertation, The University of Texas at Austin, 2022.

[18] Liu C-T. Corrosion of Stainless and Carbon Steel in Aqueous Piperazine for CO2 Capture. PhD Dissertation, The University of Texas at Austin, 2022.

[19] Frailie PT. Modeling of Carbon Dioxide Absorption / Stripping by Aqueous MDEA / PZ. PhD Dissertation, the University of Texas at Austin, 2014.

[20] Closmann F.Pilot Testing of Mitigation Methods for Piperazine Oxidation.Presented at GHGT-16,Lyon,France October 24-27,2

[21] Rochelle,G.and Hilliard,M.,University of Texas System,2011.Acid Gas Capture by Diamines.There are 7,938,887 species

[22] Rochelle,G.,Freeman,S.,Chen,X.,Nguyen,T.,Voice,A.and Rafique,H.,University of Texas System

[23] Rochelle,G.,Madan,T.and Lin,YJ,University of Texas System,2018.Apparatus for and method of removing acidic gas from a gaseous stream and regenerating an absorbent solution.Particulars 9,956,505

[24] Babu,ASand Rochelle,GT,2022.Process design of the piperazine advanced stripper for a 460 MW NGCC.International Journal of Greenhouse Gas Control,115,p.103631.

[25] Closmann, F., Rochelle, G., Gao, T., Suresh Babu, A., Abreu, M. and Drewry, B., 2021, March (商標)on NGCC at Denver City,Texas.In Proceedings of the 15th Greenhouse Gas Control Technologies Conference(pp.15-18).

[26] Rochelle,G.,Closmann,F.,Abreu,M.,Suresh Babu,A.,Drewry,B.,Gao,T.,Sexton,A.,Dombrowski,K.and Piggott,B.,Karen and Bryan,Scott R.and Bernau,Max and Sexton,Andrew and Dombrowski,Katherine and jones,Rosalind and marsh,Michael and Piggott,Brad and Myers,Duane.Cost details from Front-End Engineering Design of piperazine with the advanced stripper.(August 29,2022).

[27] Song,D.,Effect of liquid viscosity on liquid film mass transfer for packings.PhD Dissertation,The University of Texas at Austin,2017.

[28] Frailie,P.T.Modeling of carbon dioxide absorption / stripping by aqueous methyldiethanolamine / piperazine.PhD Dissertation.The University of Texas at Austin.2014..

[29] Suresh Babu,A.and Rochelle,GT,2021,March.Heat loss and energy use in pilot plant testing of Piperazine with the Advanced Stripper.In Proceedings of the 15th Greenhouse Gas Control Technologies Conference(pp.15-18).

[30] Gao, T., Absorber modeling and design in amine scrubbing for carbon capture.PhD Dissertation, The University of Texas at Austin,2021.

[31] Suresh Babu, A., Abreu, M., Drewry, B., Chen, YLand Rochelle, G., 2022. Maximum Operating Profit of PZAS at Off-Design Conditions by a Rigorous Rating Model for a 460 MW NGCC.

[0086] Incorporation by Reference and Modification Statement All references throughout this application, for example, patent documents, including issued or granted patents or equivalents and patent application publications, as well as non-patent literature or other materials, are incorporated by reference in their entirety, just as if individually incorporated by reference.

[0087] All patents and publications mentioned in this specification are indicative of the level of skill of those skilled in the art to which embodiments of this invention pertain. The references cited herein are, where appropriate, incorporated by reference in their entirety to represent the state of the art as of the filing date, and it is intended that this information may be employed herein to exclude (e.g., disclaim) certain embodiments that are in the prior art, if appropriate.

[0088]

[0013] When a group of substituents is disclosed herein, it is understood that all individual members of that group are separately disclosed, as are all subgroups and classes that can be formed using that substituent. When a Markush group or other classification is used herein, it is intended that all individual members of the group, as well as all possible combinations and subcombinations of the group, are individually included in the disclosure. As used herein, "and / or" means that one, all, or any combination of the items in the list separated by "and / or" is included in the list; for example, "1, 2, and / or 3" is equivalent to "1, 2, 3, 1 and 2, 1 and 3, 2 and 3, or 1, 2, and 3."

[0089] Any combination or permutation of components described or exemplified can be used to practice embodiments of the present invention unless otherwise specified. Specific names for materials are intended for illustrative purposes, as one of ordinary skill in the art will recognize that the same materials can be given different names. It will be understood that methods, device elements, starting materials, and synthetic methods other than those specifically exemplified can be employed to practice embodiments of the present invention without resort to undue experimentation. All art-known functional equivalents of any such methods, device elements, starting materials, and synthetic methods are intended to be included in embodiments of the present invention. Whenever a range is given herein, e.g., a temperature range, a time range, or a composition range, all intermediate and subranges, as well as all individual values ​​included in the given range, are intended to be included in the present disclosure.

[0090] As used herein, "comprising" is synonymous with "including," "containing," or "characterized by" and is inclusive or open-ended, not excluding additional, unrecited elements or method steps. As used herein, "consisting of" excludes any element, step, or ingredient not specified in the claim element. As used herein, "consisting essentially of" does not exclude materials or steps that do not materially affect the basic and novel characteristics of the claim. Any reference herein to the term "comprising," particularly in a description of a component of a composition, in a description of a method, or in a description of an element of a device, is understood to encompass compositions, methods, or devices consisting essentially of and consisting of the recited component or elements, optionally in addition to other components or elements. The inventive embodiments illustratively described herein may suitably be practiced in the absence of any element, elements, limitation, or limitations not specifically disclosed herein.

[0091] The terms and expressions which have been employed are used as terms of description and not of limitation, and there is no intention in the use of such terms and expressions to exclude any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the embodiments of the invention claimed. Thus, while the invention has been specifically disclosed by preferred embodiments and optional features, it will be understood that changes and modifications of the concepts disclosed herein may be resorted to by those skilled in the art, and that such changes and modifications are deemed to be within the scope of the invention as defined by the appended claims.

Claims

1. 1. A system comprising: a stripper column comprising a first packing section and a first inlet; a second packing section; a bypass inlet configured to deliver fluid to an upper portion of the second packing section; a first heat exchanger, the first heat exchanger including a first inlet and a first outlet; a first flow path from the first heat exchanger to the stripper column, the first flow path including the first outlet of the first heat exchanger and the first inlet of the stripper column; a second flow path from a location upstream of the first inlet of the first heat exchanger to the bypass inlet.

2. the stripper column comprises the second packing section; The system of claim 1 , wherein the stripper column includes the bypass inlet.

3. a second heat exchanger, the second heat exchanger including a first inlet and a first outlet; a third flow path; the first outlet of the first heat exchanger is in fluid communication with the first inlet of the second heat exchanger; the stripper column further comprises a second inlet; The system of claim 1 , wherein the third flow path includes the first outlet of the second heat exchanger and the second inlet of the stripper column.

4. the first heat exchanger includes a second inlet and a second outlet; the second heat exchanger includes a second inlet and a second outlet; the stripper column includes a first outlet; the first outlet of the stripper column is in fluid communication with the second inlet of the second heat exchanger; The system of claim 3 , wherein the second outlet of the second heat exchanger is in fluid communication with the second inlet of the first heat exchanger.

5. 5. The system of claim 4, further comprising a heater configured to heat a fluid between the first outlet of the second heat exchanger and the second inlet of the stripper column.

6. the stripper column comprises the second packing section; the stripper column includes the bypass inlet; the stripper column includes a second outlet; The system comprises a condenser, the condenser includes an inlet; The system of claim 4 further comprising a condenser, the inlet of the condenser being in fluid communication with the second outlet of the stripper column.

7. an absorber, the absorber including an inlet and an outlet; a recirculation flow path; the outlet of the absorber is in fluid communication with the first inlet of the first heat exchanger; the stripper column includes a first outlet; The system of claim 1 , wherein the recycle flow path includes the first outlet of the stripper column and the inlet of the absorber.

8. The system of claim 1 , wherein the second fill area ranges in height from 10 feet to 20 feet.

9. 10. The system of claim 1, wherein the stripper tower has a diameter ranging from 2 feet to 30 feet.

10. 10. The system of claim 1, wherein the stripper column has a total packing height in the range of 10 feet to 60 feet.

11. The system of claim 1 further comprising the fluid comprising an aqueous solution of an amine.

12. 1. A method for separating components from a stream, the method comprising: flowing a first portion of a first stream into an upper portion of a first packing section, the first portion of the first stream being at a first temperature, the first stream comprising the component, and the first stream being a first liquid stream at the first temperature; flowing a second portion of the first stream to a first inlet of a stripper column, the second portion of the first stream being at a second temperature, the second temperature being greater than the first temperature, and the first inlet being below the upper portion of the first packing section; flowing a third portion of the first stream into a second inlet of the stripper column, the third portion of the first stream being at a third temperature, the third temperature being greater than the second temperature, the second inlet being below the first inlet, and the third portion of the first stream being a first vapor stream at the third temperature; passing the first vapor stream through the stripper column, through the first packing section and upward; passing the first liquid stream through the first packing section and downwardly through the stripper column; transferring the component from the first liquid stream to the first vapor stream; separating said components by condensing said first vapor stream with a second liquid stream to obtain a second vapor stream containing said components.

13. 13. The method of claim 12, wherein the first packing section is in the stripper column.

14. 13. The method of claim 12, wherein condensing the first vapor stream is in a condenser and the stripper column does not include the condenser.

15. the first stream further comprising the component in a first proportion; The notation method is flowing a bottoms stream through a first outlet of the stripper column, the bottoms stream comprising a second proportion of the component, the second proportion being less than the first proportion; and cooling the bottoms stream with the second portion of the first stream.

16. 16. The method of claim 15, wherein cooling the bottoms stream further comprises cooling the bottoms stream with the third portion of the first stream.

17. flowing the first stream from an absorber; 16. The method of claim 15, further comprising: flowing the bottoms stream to the absorber.

18. the constituent is carbon dioxide, the first stream comprises a solvent; the solvent is an amine, the first stream having a first loading of greater than or equal to 0.4 moles of carbon dioxide per mole of nitrogen; 16. The method of claim 15, wherein the bottoms stream has a second load of less than or equal to 0.

2.

19. 13. The method of claim 12, wherein the third temperature is at least 130°C.

20. 13. The method of claim 12, wherein the third portion of the first stream is at a pressure of at least 2.5 bar.

21. 13. The method of claim 12, further comprising heating the third portion of the first stream to the third temperature using a steam heater.

22. 1. A system comprising: a stripper column comprising a first tray section and a first inlet; a second tray section; and a bypass inlet configured to deliver fluid to an upper portion of the second tray section; a first heat exchanger, the first heat exchanger including a first inlet and a first outlet; a first flow path from the first heat exchanger to the stripper column, the first flow path including the first outlet of the first heat exchanger and the first inlet of the stripper column; a second flow path from a location upstream of the first inlet of the first heat exchanger to the bypass inlet.

23. the stripper column includes the second tray section; 23. The system of claim 22, wherein the stripper column includes the bypass inlet.

24. a second heat exchanger, the second heat exchanger including a first inlet and a first outlet; a third flow path; the first outlet of the first heat exchanger is in fluid communication with the first inlet of the second heat exchanger; the stripper column further comprises a second inlet; 23. The system of claim 22, wherein the third flow path includes the first outlet of the second heat exchanger and the second inlet of the stripper column.

25. the first heat exchanger includes a second inlet and a second outlet; the second heat exchanger includes a second inlet and a second outlet; the stripper column includes a first outlet; the first outlet of the stripper column is in fluid communication with the second inlet of the second heat exchanger; 25. The system of claim 24, wherein the second outlet of the second heat exchanger is in fluid communication with the second inlet of the first heat exchanger.

26. 26. The system of claim 25, further comprising a heater configured to heat a fluid between the first outlet of the second heat exchanger and the second inlet of the stripper column.

27. the stripper column includes the second tray section; the stripper column includes the bypass inlet; the stripper column includes a second outlet; The system comprises a condenser, the condenser includes an inlet; 26. The system of claim 25, further comprising a condenser, the inlet of the condenser in fluid communication with the second outlet of the stripper column.

28. an absorber, the absorber including an inlet and an outlet; a recirculation flow path; the outlet of the absorber is in fluid communication with the first inlet of the first heat exchanger; the stripper column includes a first outlet; 23. The system of claim 22, wherein the recycle flow path includes the first outlet of the stripper column and the inlet of the absorber.

29. 23. The system of claim 22, wherein the stripper tower has a diameter ranging from 2 feet to 30 feet.

30. 23. The system of claim 22, further comprising the fluid comprising an aqueous solution of an amine.

31. 1. A method for separating components from a stream, the method comprising: flowing a first portion of a first stream into an upper portion of a first tray section, the first portion of the first stream being at a first temperature, the first stream comprising the component, and the first stream being a first liquid stream at the first temperature; flowing a second portion of the first stream to a first inlet of a stripper column, the second portion of the first stream being at a second temperature, the second temperature being greater than the first temperature, and the first inlet being below the upper portion of the first tray section; flowing a third portion of the first stream into a second inlet of the stripper column, the third portion of the first stream being at a third temperature, the third temperature being greater than the second temperature, the second inlet being below the first inlet, and the third portion of the first stream being a first vapor stream at the third temperature; passing the first vapor stream through the stripper column and upwardly through the first tray section; passing the first liquid stream through the first tray section and downwardly through the stripper column; transferring the component from the first liquid stream to the first vapor stream; separating said components by condensing said first vapor stream with a second liquid stream to obtain a second vapor stream containing said components.

32. 32. The method of claim 31 , wherein the first tray section is in the stripper column.

33. 32. The method of claim 31 , wherein condensing the first vapor stream is in a condenser and the stripper column does not include the condenser.

34. the first stream further comprising the component in a first proportion; The method comprises: flowing a bottoms stream through a first outlet of the stripper column, the bottoms stream comprising a second proportion of the solvent, the second proportion being less than the first proportion; and cooling the bottoms stream with the second portion of the first stream.

35. 35. The method of claim 34, wherein cooling the bottoms stream further comprises cooling the bottoms stream with the third portion of the first stream.

36. flowing the first stream from an absorber; 35. The method of claim 34, further comprising: flowing the bottoms stream to the absorber.

37. the constituent is carbon dioxide, the first stream comprises a solvent; the solvent is an amine, the first stream having a first loading of greater than or equal to 0.4 moles of carbon dioxide per mole of nitrogen; 35. The method of claim 34, wherein the bottoms stream has a second load of less than or equal to 0.

2.

38. 32. The method of claim 31 , wherein the third temperature is at least 130° C.

39. 32. The method of claim 31 , wherein the third portion of the first stream is at a pressure of at least 2.5 bar.

40. 13. The method of claim 12, further comprising heating the third portion of the first stream to the third temperature using a steam heater.

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