Patent Application
20230043712
Embodiments relate to hydrophobic, low viscosity, low vapor pressure physical solvents for carbon capture. More specifically embodiments relate to a method of separating CO2 from a gas stream using a solvent having two or more ester groups.
Future integrated gasification combined cycle (IGCC) power plants and steam methane reforming (SMR) chemical plants can generate high pressure CO2 gas streams generated from the in-situ water-gas shift reaction to produce H2, which when burned for energy, does not create any long-lasting greenhouse gas emissions. Because of the high CO2 partial pressure in the gas stream (such as 20 bar) emitted from IGCC and SMR plants, the driving force for CO2 to be absorbed from the gas stream to the solvent phase is large compared with post-combustion carbon capture, which has a very low CO2 partial pressures of only 0.1 bar in the gas stream. In addition, the high pressure of CO2 will make a physical solvent viable because a chemical solvent will become inefficient mainly due to its extremely high regeneration energy compared with physical solvents. In contrast, CO2 interaction with a physical solvent does not involve a chemical reaction. As a result, it will not need extensive energy to regenerate physical solvent.
A variety of methods have been proposed to capture CO2 from high pressure syngas (i.e. precombustion CO2 capture), including physical solvents, sorbents, and separation membranes, with continuous solvent looping systems currently being the most advanced. All commercially-available solvents for precombustion CO2 capture are operated below room temperature because they are hydrophilic and, unless they are operated at low temperature, absorbed water reduces the ability to dissolve CO2. Additionally, current state of the art CO2 solvents have appreciably high vapor pressures at room temperature that would lead to sizable loss of the solvent through evaporation. Hence, a major limitation of current commercially-available solvent processes for precombustion CO2 capture is that the solvents are operated below room temperature in order to (a) condense water before the absorption step in order to prevent water accumulation in the solvent, and (b) reduced solvent evaporation due to the sizable room temperature vapor pressure. Since these commercially-available solvents are used below room temperature, processes using such solvents are unable to make effective use of waste heat in the process in order to reduce the electricity consumption.
For example, if a physical solvent could be regenerated at higher temperature and pressure (40° C. and 10 bar vs 10° C. and 1 bar), the electricity consumption of CO2 compression would be reduced approximately in half because the electricity required to isothermally compress CO2 from 1 bar to 10 is approximately half of the electricity to isothermally compress CO2 from 1 bar to 150 bar. By operating at below room temperature, a conventional hydrophilic solvent with high vapor pressure is unable to accept waste heat and therefore unable to reduce the electricity consumption associated with compressing CO2 to the pressure needed to transport supercritical CO2 in pipelines. The presently designed hydrophobic solvents with low vapor pressure, conversely, allows for higher temperature and pressure operations (including accepting waste heat) and enable significant reduction in the cost of CO2 capture from precombustion capture applications, such as but not limited to IGCC-CCS and SMR-CCS.
Pre-combustion capture of CO2, capture of CO2 from gas streams after generation of syngas but prior to delivery to a turbine, is typically accomplished using physical solvents as opposed to the more energy intensive aqueous amine chemisorption processes necessary for post-combustion CO2 capture. Such amine chemisorption processes are more energy intensive because they require sufficient energy to break chemical bonds between CO2 and the solvent molecules and release the captured CO2 and regenerate the solvent. Physical solvent processes, conversely, require much less energy for regeneration because CO2 interaction with physical solvent does not involve covalent bonds but only involves weaker van der Waals and electrostatic interactions. Physical solvents are preferable to chemical solvents/sorbents due to their low regeneration energy and are often used to absorb CO2 from precombustion streams.
Precombustion CO2 capture typically occurs after a water gas shift (WGS) reaction in order to increase the CO2 and H2 composition of a gaseous stream and to decrease the CO composition. While precombustion CO2 capture could occur without the use of WGS reaction, this is not typically done because (a) the goal of low-GHG chemical/power plants is to generate/combust hydrogen, (b) WGS will increase the partial pressure of CO2 in the syngas, and (c) the selectivity of CO2 to H2 is typically larger than the selectivity of CO2 to CO in physical solvents. Typical WGS pre-combustion fuel gas streams consist of 30-32% CO2, 43% H2, 23% H2O, 3% other gases such as CO, COS, H2S and the total gas stream pressure is about 50 bar
Current state-of-the-art CO2 capture solvents for pre-combustion processes, such as IGCC systems, are listed in
While water removal is important for natural gas pipeline applications, it is not favorable for applications in which the fuel stream is directly combusted onsite, as would be the case in IGCC systems. For CO2 capture and sequestration, high uptake of water by the solvent is detrimental in several ways. One of the biggest detriments of water uptake by the solvent is reduced CO2 uptake capacity. Computational modeling results indicate that CO2 capacity and CO2/H2 selectivity of the DEPG is negatively impacted by co-absorption of water due to the stronger binding energy of water for the ether oxygens of that composition. Other reasons that water uptake by the solvent is detrimental for the IGCC system include reduced purity of the captured CO2 stream and the need for lower temperatures for the capture process, the equipment corrosion due to water absorption in the solvent.
Existing commercial CO2 solvents, while possessing some advantages, also have disadvantages. For example, PC and NMP can be operated at lower temperatures than DEPG without experiencing viscosity increases or forming slurries. DEPG, however, possesses superior thermal stability over PC and NMP, which allows removal of H2O by thermal swing processes at elevated temperatures. These results suggest that a hydrophobic solvent with otherwise similar physical properties and CO2 capacity to DEPG would outperform PC, NMP, and DEPG.
As DEPG and other commercial solvents are hydrophilic, water accumulation over time in those solvents will greatly reduce their efficiency. In processes using those solvents, the moisture content of the water saturated pre-combustion gas stream needs to be addressed before the CO2 capture step and/or the water-laden solvent needs to be stripped of water at elevated temperatures and then re-cooled prior to contacting the CO2 solvent.
As shown in
Water laden solvent can also add energy penalties and equipment costs to CO2 absorbing processes by (a) requiring additional drying of the recovered CO2 prior to pipeline transport, (b) removing water from the pre-combustion fuel gas stream which is needed as an energy-generation source in the combustion turbine, (c) increasing the solvent density and viscosity of DEPG due to water absorption which increases energy demands for pumping the solvent and adds to the absorber size due to slower CO2 mass transfer rates, and (d) increasing corrosion rates requiring more expensive stainless steel materials. All the above-described disadvantages of current commercial CO2 sorbents can be minimized using hydrophobic, low vapor pressure, and low viscosity solvents which do not tend to take up water. An ideal physical solvent would absorb as much CO2 and as little H2O and H2 as possible for efficient capture of CO2.
Thus, there is a need in the art for hydrophobic CO2 solvents that can perform better than current state-of-the-art-hydrophilic solvents. The hydrophobic ester-based solvents disclosed herein are demonstrated to have physical properties and CO2 uptake which are highly competitive with PC while having lower water absorption. This combination of high CO2 absorption capacity, the ability to run at a range of room to warm temperatures, and reduced water uptake provide key advantages in applications where water does not need to be removed from the treated gas in order to meet pipeline specification, e.g. IGCC CO2 capture in which the syngas is combusted onsite.
One object of at least one embodiment of the present invention is related to providing a method for separating CO2 from a gaseous stream using a physical solvent. In an embodiment, the solvent is at least one ester, and wherein said at least one ester comprises two or more alkyl-ester functional groups on a central hydrocarbon chain. The utilized solvents are hydrophobic, operable over a wide range of temperature and pressures, have low vapor pressure and low viscosity, and are non-corrosive.
The solvents identified can be used as physical solvents for the separation of CO2 from synthesis gas mixtures in carbon capture processes. These solvents can be structurally tuned or blended to possess the optimal physical parameters (viscosity, volatility, density, melting point) for the particular process to be employed, while maintaining high CO2 loading capacity, high CO2/H2 solubility selectivity, and a low tendency to absorb water.
The invention provides a method for removing CO2 from a gaseous stream containing CO2 comprising: contacting the gaseous stream containing CO2 with a solvent at a first temperature and a first pressure to dissolve said CO2 in said solvent, wherein the solvent is at least one ester, and wherein said at least one ester comprises two or more alkyl-ester functional groups on a central hydrocarbon chain.
The invention together with the above and other objects and advantages will be best understood from the following detailed description of the preferred embodiment of the invention shown in the accompanying drawings, wherein:
12A is a plot of gravimetric water absorption from humidified N2 at 25° C., in accordance with the features of the present invention;
The foregoing summary, as well as the following detailed description of certain embodiments of the present invention, will be better understood when read in conjunction with the appended drawings.
In an embodiment, the gaseous stream 12 comprises any stream of gasses containing CO2. Exemplary gaseous streams 12 comprise products from a syngas-generating process eluting from the source 14. In an embodiment, the products from a syngas-generating process comprise H2, CO2, and H2O and represent a syngas stream (combination of H2 and CO) that has been through a water gas shift reaction. Where the gaseous stream comprises products from a syngas-generating process, the components can be present in any proportion, with typical compositions comprising between approximately 10 mol % and approximately 70 mol % H2, and between approximately 20 mol % and approximately 80 mol % CO2, where the stream is saturated with water. Where the syngas products have not gone through the water gas shift reaction CO will be present, with CO2 and H2O present in lower amounts than in post-WGS reaction streams.
In an embodiment, the source 14 is any source of CO2, syngas, or combinations thereof. Exemplary sources include solid fuel gasification plants (IGCC) with the solid fuel being coal, biomass, or solid waste partially oxidized using either air or pure oxygen. Further exemplary sources include natural gas steam methane reforming SMR plants, and/or petroleum refineries reforming gaseous or liquid fuels into hydrogen and carbon dioxide.
A salient feature of the invention is the solvent 18 used to contact the gaseous stream 12. In an embodiment, the solvent is a physical solvent comprising one or more esters wherein the esters comprise at least two alkyl-ester functional groups on a central hydrocarbon chain. Specifically, the solvent 18 used in the instant invention is an ester or combination of esters selected from esters represented by the general formulae for suitable diesters 40, tri-esters 42, or tetra-esters 44 shown in
Embodiments of the invention use neat, pure compounds as solvent 18 (i.e. one ester at a time). In other embodiments one or more esters are combined, the combination used as the solvent 18. In still other embodiments, one or more ester compounds are combined with minor additives to create the solvent 18, wherein the additives do not affect the bulk properties of the solvent, wherein such additives include anti-microbial agents, anti-scaling agents, anti-foaming agents, anti-corrosion additives, and combinations thereof. In yet another embodiment, the solvent 18 comprises at least one of the esters shown in
After the contacting step 52, the method continues by regenerating 54 the solvent 18 by heating the solvent containing dissolved CO2, reducing the pressure within the absorber vessel containing the solvent containing dissolved CO2, or a combination thereof. The regenerating step 54 of the invented method is performed at a second temperature and pressure.
A salient feature of the present invention is the ability of the contacting step 52 of the invented method to be performed at the first temperature and pressure. Said first temperature and pressure are higher than prior art processes that require cooler temperatures of −40° C. to 10° C. Suitable first temperatures are between approximately −15° C. and approximately 100° C., with typical first temperatures between approximately 20° C. and approximately 50° C. Suitable first pressures are between approximately 5 bar to approximately 100 bar, with typical first pressures between approximately 10 bar to approximately 60 bar. In an embodiment, the first temperature is above approximately room temperature, i.e. above approximately 20° C. As described herein, the first temperature is the initial temperature of the solvent prior to initial contact with the gaseous stream. As described herein, the first pressure is the initial pressure of the gaseous stream prior to initial contact with the solvent.
In an embodiment, during the regeneration step 54, the invented method utilizes a lower second temperature and pressure than prior art methods. In an exemplary embodiment, the suitable second temperatures are between approximately 10° C. to approximately 180° C., with typical second temperatures between approximately 40° C. and approximately 120° C. Suitable second pressures are between approximately 1 bar to approximately 25 bar, with typical second pressures between approximately 5 bar to approximately 15 bar. Given the relatively mild temperatures and pressures used in the regeneration step of the invented method, waste heat or low grade heat is suitable for heating the solvent containing dissolved CO2 to regenerate said solvent. As described herein, the second temperature is the temperature to which the solvent is heated to remove CO2. As described herein, the second pressure is the pressure of CO2 leaving the solvent during the regenerating step.
In order to facilitate use of said higher first temperature and pressure, suitable solvents are needed. The inventors have identified several specific solvents within the generic structures shown in
Another salient feature of the invented method is the ability to separate CO2 from a gaseous stream that also contains H2O while absorbing little to no water. In an embodiment, the invented method solvates CO2 from a gaseous stream also containing H2O to concentrations equal to or greater than prior art methods. In order to facilitate this feature, the solvents used herein are hydrophobic where current commercial solvents are hydrophilic. In an exemplary embodiment, the invented method solvates between approximately 6.5 mol CO2 per liter of solvent and approximately 9.0 mole CO2 per liter of solvent at a solvent temperature of 10° C. and a CO2 partial pressure of 25 bar or between approximately 4.0 mol CO2 per liter of solvent and approximately 5.5 mol CO2 per liter of solvent at a solvent temperature of 25° C. and a CO2 partial pressure of 25 bar. In an embodiment, the solvent 18 of the instant method has a water solubility of between approximately 0.2 mol/L of H2O and approximately 2 mol/L of H2O at 25° C.
Yet another salient feature of the invented method is the CO2/H2 selectivity of the method. As the invented method separates CO2 from pre-combustion syngas streams containing at least H2 and CO2 while minimizing the solvation of the H2, said selectivity ratio is an important feature. In an exemplary embodiment, the CO2/H2 of the invented method is greater than approximately 50 and is typically between approximately 60 and approximately 90.
Still another salient feature of the invented method is the low vapor pressure of the solvents utilized. The solvents used in this method are designed specifically to minimize the volatility of said solvents to minimize the cost and difficulty associated with replenishing the solvents and to limit the necessity of separating solvent from gas streams that have been stripped of CO2. In an exemplary embodiment, the invented method features solvents having a low vapor pressure with boiling points between approximately 180° C. to over 300° C. for diesters with higher boiling points for tri- and tetra-esters.
Still yet another salient feature of the invention is the ability to perform the contacting step 52 of the invented method at elevated temperatures and pressures. Prior art methods require significant cooling and depressurizing of gaseous streams containing CO2 before contacting said streams with their CO2 solvent. Conversely, the invented method is suitable for separating CO2 from gaseous streams having any partial pressure of CO2 with typical CO2 partial pressures between approximately 15 bar and approximately 30 bar, and H2 partial pressures between approximately 5 bar and approximately 35 bar. The gaseous stream may also be saturated with water vapor, with relative humidity varying approximately between 50 and 100%.)
Another salient feature of the invention is the makeup of the solvents used to solvate CO2. The solvents used in the invented method are comprised of only C, H, and O atoms. Prior art solvents or sorbents require the use of silica, various nitrogen compounds/groups, and/or various fluorine compounds/groups. Any of these non-carbon, hydrogen, or oxygen substances have to be separated from gas streams that will go through a turbine or said turbine will be damaged. As the instant invention does not use any of these non-carbon, hydrogen, or oxygen substances, no step to remove contaminants is needed after CO2 capture and before the CO2 scrubbed gaseous stream is put through a turbine.
Still yet another salient feature of the invention is the low corrosive nature of the solvents used. Surprisingly and unexpectedly, empirical testing has demonstrated that the solvents used in the invented method have a corrosion rate of less than around 0.5 microns/year (0.005 mm/year) when a carbon steel or stainless-steel coupon is immersed in the solvent at a temperature of about 21° C. and in the presence of CO2 at a pressure of 100 psig. In an embodiment, the corrosion caused by use of the instant solvent on carbon or stainless steel is negligible or immeasurable.
Still yet another salient feature of the invention is the low vapor pressure and viscosity of the solvents during performance of the invented method. In an embodiment, the solvents have a vapor pressure between approximately 0.001 Pa and approximately 10 Pa during performance of the instant method. Additionally, the solvents have a viscosity between approximately 1 cP and approximately 15 cP during performance of the invented method.
In an embodiment, the properties of the solvent 18 can be tailored to the conditions of the process utilizing the invented method. For example, low molecular weight, low viscosity solvents such as CASSH-1 to CASSH-6 are particularly suitable for lower temperature applications in the −15° C. to 30° C. range and higher molecular weight (i.e. higher than CASSH-1 to CASSH-6), moderate viscosity solvents are suitable for higher temperature operations in the 30° C. to 70° C. range. Water tolerance can also be tailored to the solvent with water solubilities spanning a range of 0.5-2.5 wt % depending on solvent. The diester 40, tri-ester 42, and tetra ester 44 solvents shown in
Surprisingly and unexpectedly, the invented method achieves commensurate or superior CO2 solubility and CO2/H2 selectivity compared with state-of-the-art methods while utilizing hydrophobic rather than hydrophilic solvents. As a result, the current method performs as well or better than prior art methods by dissolving superior or commensurate amounts of CO2 in a stream containing CO2, H2, and H2O wherein the present method uptakes little to no water and has extremely low corrosion rates. Prior art methods utilize hydrophilic solvents that dissolve copious amounts of water along with CO2 and therefore have many disadvantages detailed above.
All diesters described herein are commercially available and were purchased from either TCI or Sigma-Aldrich. The tri-ester solvents described herein were derived from commercially available triols such as trimethyol ethane or trimethylol propane and then converted in-house to the corresponding esters via an esterification reaction, wherein the triol is reacted with the appropriate anhydride, preferably acetic, iso-butyric, or n-butyric anhydride. The tetra-esters, also known as citrates, described herein were prepared from either commercially available trialkyl citrates or citric acid which was then functionalized at the three acid sites and the one alcohol site. A procedure to generate the ester solvents disclosed herein is described by Chauhan et al., “Indium Triflate: An Efficient Catalyst for Acylation Reactions,” Synlett, No. 11, 1999, pp. 1743-1744, the entirety of which is incorporated by reference herein.
As discussed herein, the instant method utilizes various ester solvents to dissolve CO2 from a gaseous stream also containing H2O. A series of experiments was performed to characterize the performance of the invented method using the above-described solvents.
Gravimetric CO2 adsorption measurements for solvents were obtained using a Hiden IGA-003 microbalance (Warrington, England). Samples (30-60 mg) were loaded into an open glass container which was suspended from a microbalance assembly inside of a pressure cell. The solvents were outgassed at reduced pressure (10-50 mbar) at 25° C. in flowing N2 for a minimum of 1 hr prior to introduction of pure to make adsorption measurements.
Isotherms were measured in a thermostated sample chamber at increasing pressure steps under flowing gas regulated by a mass flow controller and a back pressure regulator. The samples were held at the target pressures until >90% of the equilibrium CO2 absorption was established (typically 30-90 min). The final CO2 absorption equilibrium loading was then calculated by an asymptotic fit to the sample weight versus time curve. Buoyancy corrections were applied to the final equilibrium weights using known densities of the samples and all components in the sample and counter weight chambers using gas densities calculated with The National Institute of Standards and Technology's software titled “Reference Fluid Thermodynamic and Transport Properties.” Evaporative losses (determined by the difference in starting weight and final weight at 1 bar) over the course of the measurements were insignificant in relation to the mass increase due to CO2 adsorption for all of the solvents of interest at the conditions reported herein.
Karl Fischer titrations were performed according to the procedure described in ASTM E203—16 Standard Test Method for Water Using Volumetric Karl Fischer Titration, the entirety of which is incorporated by reference herein.
Henry's law constants were determined by calculating the slope of absorption isotherms at low pressure. The Henry's law constants were used to calculate working CO2 capacities.
The relative corrosion rates of C1020 carbon were studied under the following conditions: 21° C. and 100 psig CO2, 21° C. and 400 psig CO2, 40° C. and 100 psig CO2, and 40° C. and 400 psig CO2. The corrosion rates were determined gravimetrically according to ASTM G1-03, Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens, the entirety of which is incorporated by reference herein.
Diethyl sebacate “CASSH-1” was initially identified as a potential high performing CO2 solvent as described above. Subsequent experimental characterization of CASSH-1 verified its high CO2 uptake, low H2 uptake, and low moisture affinity. Guided by these encouraging results, research was expanded and more systematic experimental screening tests for CO2 solubility in 18 commercially available diester “CASSH” solvents were completed to establish a correlation between molecular structure and volumetric CO2 uptake. The structures of the 18 diesters that were characterized are shown in
Through the testing of the 18 diesters shown in
The lower molecular weight solvents CASSH-4, CASSH-5, and CASSH-6 are ideally suited as a CO2 solvent under chilled gas conditions between approximately −15° C. and approximately 10° C. where CO2 loading capacity is maximized, and solvent vaporization is negligible. The relatively high boiling points (217° C.-245° C.) of the solvents make them suitable for regeneration near room temperature with minimal evaporation loss. All the CASSH solvents described herein have CO2 heats of absorption in the range of 14-17 kJ/mol.
Analysis of the CO2 solubility data for the solvents shown in
Following the initial experimental CO2 solubility screening test, additional characterizations of the solvents by water solubility, H2 solubility (computational models), and physical properties (melting point, boiling point, viscosity) were undertaken. Water absorption tests done using the Karl Fisher titration technique combined with results from the scientific literature for the CASSH series are compared with the most common least hydrophilic commercialized solvents, PC and TBP, with the data shown in
A sample of DEPG was stored in an open vial within a sealed cabinet purged with humidified N2 over two weeks and the weight of the sample was recorded at intervals with the results shown in
For applications at lower temperatures and higher pressures, CO2 uptake deviates much more from Henry's Law than does H2 to give CO2 isotherms like those in
A summary of properties for the CASSH solvents are compared against the commercial solvents PC, which has the most similar properties in terms of CO2 and water solubility and physical properties, and DPEG. The results are summarized in
While numerous diester derivatives are feasible for capture in the range of between approximately −15° C. and approximately 25° C., derivatives derived from diacids consisting of 4-10 carbons in length with terminal alkyl groups ranging from C1 to C4 are most favored due to factors such as melting points, boiling points, viscosities, and predicted CO2 uptake based on the correlation shown in
In an embodiment, it can be determined whether diesters other than those shown and described herein and in the accompanying figures based on where those solvents would land on the correlation plot shown in
moles ester functional group per liter=(number of ester functional groups in the molecule)(density of multiester)/(molecular weight of multiester) EQUATION 1
The CO2/H2 selectivities listed for CASSH solvents were computed using the relevant Henry's Constants for CO2 and H2. These values are expected to be significantly higher under low temperature conditions due to the deviation from Henry's Law for CO2 uptake. PC results are taken from Burr et al., “Which physical solvent is best for acid gas removal?” Hydrocarbon Processing, 2009, vol. 88, is. 1, pp 43-50 the entirety of which is incorporated by reference herein.
While the above discussion mainly focused on solvents designed for typical process operating conditions in the range of absorber temperatures between approximately −15° C. and approximately 10° C. with CO2/H2 mixtures containing CO2 partial pressures in the range of between approximately 15 and approximately 30 bar and regeneration conditions between approximately 25° C. and approximately 35° C., between approximately 1 bar to approximately 2 bar, initial IGCC-CO2 capture modeling studies indicate the benefits for operating the absorber at warmer temperatures near approximately 40° C. with higher regeneration temperatures of between approximately 70 and approximately 100° C. using waste heat from a chemical/power plant. The higher operating temperatures in this process would require thermally stable solvents with high boiling points (low vapor pressures) in excess of 275° C. while maintaining low water uptake and low viscosities. Of the widely used commercial solvents, only DEPG or TBP would meet the boiling point and stability requirements. However, as noted above, DEPG is very hydrophilic and would suffer greatly under the higher water partial pressures at 40° C. compared to those at 10° C. For these proposed warm gas operations, CASSH-1 and CASSH-2 would be suitable diester solvents due to their high CO2 uptake and extremely low water solubility, with CASSH-3 also an option.
As described above and shown in
Tri-ester and citrate solvents can be tailored in a similar fashion to the diester CASSH solvents to optimize their CO2 capacity and other physical properties. The plots in
Pilot scale testing was performed by the Energy & Environmental Research Center at the University of North Dakota (UND EERC) by shipping solvents to their precombustion capture facility and testing at the pilot scale. Flow and gas make-up parameters for the pilot scale testing is shown in TABLE 2 below. TABLE 3 provides pilot testing performance data for various solvents.
For the pilot testing whose data is shown in TABLE 3, CO2 partial pressure in syngas was ˜2.6 MPa and H2S partial pressure in syngas was ˜0.02 MPa. For 10° C.-25° C. inlet cases, the solvent was regenerated at 43° C. For the 40-55° C. inlet cases, the solvent was regenerated at approximately the temperature that it leaves the absorption column, no additional heat was supplied if the solvent was already greater than 43° C.
In TABLE 3, a* indicates that An absorber temperature range is provided for each nominal solvent temperature. The lower temperature is the absorber inlet solvent temperature (solvent enters at the top of the absorption column) and the higher temperature is the solvent temperature at the bottom of the absorption column. As the syngas enters at approximately 38° C. and the absorption process is exothermic, there is a temperature gradient from the top to bottom of the column. PEGDME solvent testing was not conducted at the highest solvent inlet temperature of 55° C. and data was not included if mass balance errors were greater than 20% (which was the case for data collected with PEGDME at 40° C.).
A final, but significant advantage of the instant invention applications is its anticipated effect on reducing corrosion rates. Corrosion rate models were calculated using OLI software package for carbon steel are shown in TABLE 4. There is a dramatic decrease in corrosion rate predicted as the water content in the solvent is decreased. Even a relatively hydrophilic solvent such as DEPG shows a marked decrease in corrosion rates over aqueous solutions of K2CO3 and methyldiethanolamine (MDEA) due to lower water concentrations. When the solvent becomes even more hydrophobic as with the CASSH series of solvents, the corrosion rate drops many orders of magnitude below DEPG, and well below the ideal rate of 0.01 mm/yr. With a predicted corrosion rate of practically zero, hydrophobic solvents will provide exceptional benefits to preserving process infrastructure against degradation and produce substantial savings in initial construction and yearly maintenance costs.
TABLE 4 depicts the calculated corrosion rate of carbon steel at 40° C. in equimolar CO2/H2 at 50 bar (in mm/yr). Models were performed using OLI software package on generic carbon steel. Ideal corrosion rate is <10 μm/yr, though <50 μm/yr can be acceptable for many applications.
Corrosion data has been collected for CASSH-1, the data provided in
The measured corrosion rates in
The relative corrosion rates of C1020 carbon steel in the presence of CASSH-11, dry DEPG, and DEPG containing only 2 wt. % water was studied under the following conditions: 21° C. and 100 psig CO2, 21° C. and 400 psig CO2, 40° C. and 100 psig CO2, and 40° C. and 400 psig CO2. The corrosion rates were determined gravimetrically according to ASTM G1-03, Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens. The rates obtained are illustrated in
The solvents used in the invented method are superior to solvents used in the prior art. The presently used solvents 18 are low in viscosity, hydrophobic, low in vapor pressure, and high in CO2/H2 absorption selectivity, and low in water solubility, for example. The solvents are well suitable to remove CO2 from a stream of syngas that has gone through the water gas shift, i.e. remove CO2 from a combined stream of CO2, H2 and H2O. As physical solvents, the solvents described herein are suitable for a combined temperature swing/pressure swing operation in the exemplary temperature range between approximately −15° C. to approximately 100° C. with exemplary CO2 partial pressures in the range of approximately 15 to approximately 30 bar during absorption and between approximately 10° C. and approximately 180° C. and between approximately 1 to approximately 25 bar for regeneration.
The solvents described herein have superior properties in certain aspects over prior art solvents and also share beneficial or necessary properties of prior art solvents to aid in dissolving CO2 in the invented method as described above. For example, the solvents described herein have similar boiling points, viscosities, and CO2 and H2 solubilities as common commercial solvents used in similar applications, but with significantly lower water solubilities. The disclosed solvents are also stable under the intended operating conditions and have environmental advantages including low toxicity, high biodegradability, and do not contain any chemical elements other than H, C, or O that can cause turbine damage if any solvent should make its way into the combustion process.
Considering the aforementioned advantages and disadvantages of PC, NMP, and DEPG, it is apparent that a hydrophobic solvent with similar physical properties which can operate at low temperatures with comparable CO2 solubility could offer significant benefits as a CO2 mitigation solvent. The current invention addresses this need through the development of hydrophobic CO2 physical solvents.
Having described the basic concept of the embodiments, it will be apparent to those skilled in the art that the foregoing detailed disclosure is intended to be presented by way of example. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations and various improvements of the subject matter described and claimed are considered to be within the scope of the spirited embodiments as recited in the appended claims. Additionally, the recited order of the elements or sequences, or the use of numbers, letters or other designations therefor, is not intended to limit the claimed processes to any order except as may be specified. All ranges disclosed herein also encompass any and all possible sub-ranges and combinations of sub-ranges thereof. Any listed range is easily recognized as sufficiently describing and enabling the same range being broken down into at least equal halves, thirds, quarters, fifths, tenths, etc. As a non-limiting example, each range discussed herein can be readily broken down into a lower third, middle third and upper third, etc. As will also be understood by one skilled in the art all language such as up to, at least, greater than, less than, and the like refer to ranges which are subsequently broken down into sub-ranges as discussed above. As utilized herein, the terms “about,” “substantially,” and other similar terms are intended to have a broad meaning in conjunction with the common and accepted usage by those having ordinary skill in the art to which the subject matter of this disclosure pertains. As utilized herein, the term “approximately equal to” shall carry the meaning of being within 15, 10, 5, 4, 3, 2, or 1 percent of the subject measurement, item, unit, or concentration, with preference given to the percent variance. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the exact numerical ranges provided. Accordingly, the embodiments are limited only by the following claims and equivalents thereto. All publications and patent documents cited in this application are incorporated by reference in their entirety for all purposes to the same extent as if each individual publication or patent document were so individually denoted.
All numeric values are herein assumed to be modified by the terms “about” or “approximately,” whether or not explicitly indicated. The terms “about” or “approximately” generally refer to a range of numbers that one of skill in the art would consider equivalent to the recited value (e.g., having the same function or result). In many instances, the terms “about” and “about” include numbers that are rounded to the nearest significant figure.
The recitation of numerical ranges by endpoints includes all numbers within that range (e.g. 1 to 5 includes 1, 1.5, 2, 2.75, 3, 3.80, 4, and 5).
One skilled in the art will also readily recognize that where members are grouped together in a common manner, such as in a Markush group, the present invention encompasses not only the entire group listed as a whole, but each member of the group individually and all possible subgroups of the main group. Accordingly, for all purposes, the present invention encompasses not only the main group, but also the main group absent one or more of the group members. The present invention also envisages the explicit exclusion of one or more of any of the group members in the claimed invention.
This Utility Patent application claims priority benefit as a U.S. Non-Provisional of U.S. Provisional Patent Application Ser. No. 63/223,422, filed on Jul. 19, 2021, currently pending, the entirety of which is incorporated by reference herein.
The United States Government has rights in this invention pursuant to the employer-employee relationship of the Government to the inventors as U.S. Department of Energy employees and site-support contractors at the National Energy Technology Laboratory.
| Number | Date | Country | |
|---|---|---|---|
| 63223422 | Jul 2021 | US |
