Patent Application
20230078337
This present disclosure relates generally to methods and compositions for carbon capture, more specifically, there is disclosed various solvents used in carbon capture and methods of using such.
Carbon capture using aqueous amine solutions with chemical reaction has been adapted for treating dilute and low-pressure flue gases released from industrial processes. However, current amine-based carbon capture processes have several drawbacks. One drawback is the inability to provide high absorption and desorption rates of CO2. Another drawback is the inability to achieve high CO2 capture capacity while consuming a very small heat duty. Other drawbacks are specific to the type of amine used.
For example, primary amines such as monoethanolamine (MEA) form a very stable carbamate with CO2 which requires a high regeneration energy in its break-down process. As another example, secondary amines such as diethanolamine (DEA) can directly react with NOx, a common impurity in fossil fuel fired flue gas, emitting potentially toxic nitrosamines with the off-gas. Tertiary amines such as methyldiethanolamine require less heat for regeneration compared to the other amines, but they still suffer from having a slow rate of reaction with CO2, thus affecting the capture performance in terms of kinetics. Polyamines, such as piperazine (PZ), poses a threat because it is a secondary amine which can form nitrosamine emissions. All of these drawbacks can hinder the carbon capture process.
In addition, issues like amine loss by degradation, off-gas emission, amine volatilization, amine corrosion, and amine foaming often plague the carbon capture process. These operational issues can prevent a capture plant from achieving the original design conditions and performance goals. Emissions of degradation products can jeopardize an amine-based CO2 capture plant itself by creating the possibility of unscheduled down times or even forcing the plant to shut down unnecessarily due to the plant being too toxic to continue to operate.
Therefore, there is a need to improve the efficiency associated with using amines and/or amine-based solutions in carbon capture, especially for treating dilute and low-pressure flue gases released from industrial processes. In particular, there is a need to develop new amine solvents that have one or more of the following desirable CO2 capture properties: high absorption, high cyclic capacity, fast reaction kinetics, low corrosion, low degradation, and satisfactory heat duty requirements for solvent regeneration.
According to one aspect of the present invention, there is described methods and compositions for carbon capture. In some embodiments, the methods and compositions may be applied to capture carbon dioxide from the exhaust stream of hydrocarbon burning emitters.
According to one aspect of the present invention, there is provided a solvent for extracting carbon dioxide from a gaseous mixture, the solvent comprising diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), and water.
According to one aspect of the present invention, there is provided a solvent for extracting carbon dioxide from a gaseous mixture, the solvent comprising DEAE, HMDA, and polyethylenimine (PEI).
According to a preferred embodiment of the present invention, DEAE is present in molar concentration ranging from 2.0M to 4.0M.
According to a preferred embodiment of the present invention, HMDA is present in molar concentration ranging from 0.1M to 1.0M.
According to a preferred embodiment of the present invention, PEI is present in molar concentration ranging from 0.001M to 0.5M.
According to a preferred embodiment of the present invention, the total molar concentration of the solvent is in the range of 2.10M to 5.5M.
According to a preferred embodiment of the present invention, the solvent consists essentially of diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), polyethylenimine (PEI), and water.
Most preferably, in the present invention, DEAE is present in molar concentration of 3.6M, HMDA is present in molar concentration of 0.4M, and PEI is present in molar concentration of 0.01M.
According to a preferred embodiment of the present invention, the solvent has a heat duty below 160 kJ/mol CO2.
More preferably, in the present invention, the solvent has a heat duty below 138.9 kJ/mol CO2.
According to a preferred embodiment of the present invention, the solvent has an initial absorption rate greater than
More preferably, in the present invention, the solvent has an initial absorption rate greater than
According to a preferred embodiment of the present invention, the solvent has an initial desorption rate greater than
More preferably, in the present invention, the solvent has an initial desorption rate greater than
According to a preferred embodiment of the present invention, the solvent has a cyclic capacity greater than
More preferably, in the present invention, the solvent has a cyclic capacity is greater than
According to a preferred embodiment of the present invention, the solvent has a lean loading of 0 at 110° C.
According to a preferred embodiment of the present invention, the solvent has a viscosity below 10 mPa·s at 30° C.
According to a preferred embodiment of the present invention, the solvent has an alkalinity in the range of 9.5 to 11.0 pKa at room temperature.
According to one aspect of the present invention, there is provided a solvent for extracting carbon dioxide from a gaseous mixture, the solvent comprising DEAE, HMDA, and PEI, wherein DEAE is present in molar concentration ranging from 3.6M to 4.5M and HMDA is present in molar concentration ranging from 0.15M to 0.5M.
More preferably, in the present invention, DEAE is present in molar concentration ranging from 3.3M to 3.9M, HMDA is present in molar concentration ranging from 0.3M to 0.5M, and PEI is present in molar concentration ranging from 0.005M to 0.015M.
Most preferably, in the present invention, PEI is present in molar concentration of 0.01M.
According to one aspect of the present invention, there is provided a method of performing carbon capture comprising collecting a flue gas comprising carbon dioxide from a flue gas emitting source and exposing the collected flue gas to a solvent according to a preferred embodiment of the present invention for a period of time sufficient to remove at least a portion of said carbon dioxide gas present in said flue gas.
According to one aspect of the present invention, there is provided an apparatus for performing carbon capture comprising components configured to perform a method of performing carbon capture comprising: collecting a flue gas, comprising carbon dioxide from a flue gas emitting source; and exposing the collected flue gas to a solvent according to a preferred embodiment of the present invention for a period of time sufficient to remove at least a portion of said carbon dioxide gas present in said flue gas.
According to one aspect of the present invention, there is provided a system for performing carbon capture comprising components configured to perform a method of performing carbon capture comprising: collecting a flue gas, comprising carbon dioxide from a flue gas emitting source; and exposing the collected flue gas to a solvent according to a preferred embodiment of the present invention for a period of time sufficient to remove at least a portion of said carbon dioxide gas present in said flue gas.
According to one aspect of the present invention, there is provided the use of a solvent according to a preferred embodiment of the present invention to perform carbon capture.
According to one aspect of the present invention, there is provided a solvent for extracting carbon dioxide from a gaseous mixture, the solvent comprising:
According to a preferred embodiment of the present invention, compound I is a tertiary amine, having a chemical formula of (R1)(R2)N(CnH2n—OH), where R1 and R2 are independently a linear or branched alkyl group with a carbon number between 2 to 4.
According to a preferred embodiment of the present invention, compound I is a tertiary amine, having a chemical formula of (R1)(R2)N(CnH2n—OH), where R1 and R2 are independently a linear or branched alkyl group with a carbon number between 1 to 6, and n is an integer between 2 to 4.
According to a preferred embodiment of the present invention, compound II comprises two primary amino groups, having a chemical formula of NH2— (CmH2m)—NH2, where m is an integer between 4 to 8.
According to one aspect of the present invention, there is provided a solvent that may be used for extracting carbon dioxide from a gaseous mixture. According to a preferred embodiment of the present invention, the solvent comprises one or more of diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), polyethylenimine (PEI), and water.
In some preferred embodiments, the molar concentration of the DEAE is in the range of 2.0M to 4.0M. In some preferred embodiments, the molar concentration of the HMDA is in the range of 0.1M to 1.0M. In some preferred embodiments, the molar concentration of the PEI is in the range of 0.001M to 0.5M. In some preferred embodiments, the total molar concentration of the solvent is in the range of 2.101M to 5.5M. As the person skilled in the art will understand, the total molar concentration of the solvent refers to the concentration of the compounds which form the solvent while excluding water.
In some preferred embodiments, the solvent consists essentially of diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), polyethylenimine (PEI), and water. In some preferred embodiments, the molar concentration of the DEAE is 3.6M, the molar concentration of the HMDA is 0.4M, and the molar concentration of the PEI is 0.01M.
According to a preferred embodiment of the present invention, the PEI is a branched PEI. According to a preferred embodiment of the present invention, the molar mass of the PEI ranges from 400 g/mol to 1200 g/mol. Preferably, the molar mass of the PEI ranges from 600 g/mol to 1000 g/mol. In some preferred embodiments, the molar mass for the PEI is approximately 800 g/mol.
In some preferred embodiments, the PEI has the CAS Registry Number CAS #25987-06-8.
In some preferred embodiments, the solvent has a viscosity below 10 mPa·s at 30° C. In some preferred embodiments, the solvent has an alkalinity in the range of 9.5 to 11.0 pKa at room temperature.
Advantageously, some preferred embodiments of the solvent may have a heat duty that is about 3.85 times lower than that of MEA. For example, some preferred embodiments of the solvent may have a heat duty below about 160 kJ/mol CO2 (e.g., below about 138.9 kJ/mol CO2). This can provide a major reduction in energy input costs and operating costs for carbon capture methods, systems and/or apparatuses that use the solvent.
Advantageously, some preferred embodiments of the solvent may have an initial absorption rate that is about 37% higher than that of MEA. For example, some preferred embodiments of the solvent may have an initial absorption rate that is greater than about
This can reduce the size and/or cost of carbon capture systems and/or apparatuses that use the solvent.
Advantageously, some preferred embodiments of the solvent may have an initial desorption rate that is about 3.85 times higher than that of MEA. For example, some preferred embodiments of the solvent may have an initial desorption rate that is greater than about
This can reduce the size and/or cost of carbon capture systems and/or apparatuses that use the solvent.
Advantageously, some preferred embodiments of the solvent may have a cyclic capacity that is 85% higher than that of MEA. For example, some preferred embodiments of the solvent may have a cyclic capacity greater than
This can reduce the volume of the solvent required in carbon capture processes, and reduce the size and/or cost of carbon capture systems and/or apparatuses that use the solvent.
Advantageously, some preferred embodiments of the solvent may have a lean loading of approximately 0 at 110° C. This can help achieve nearly complete release of captured CO2 at lower relative temperatures, which is expected to further reduce energy requirements systems and/or apparatuses that use the solvent.
According to a preferred embodiment of the present invention, the solvent may have any one or more of the following properties: a heat duty below 160 kJ/mol CO2, an initial absorption rate greater than
an initial desorption rate greater than
a cyclic capacity greater than
a lean loading of 0 at 110° C., a viscosity below 10 mPa·s at 30° C., and an alkalinity in the range of 9.5 to 11.0 pKa at room temperature.
According to a preferred embodiment of the present invention, the solvent may have any one or more of the following properties: a heat duty below 138.9 kJ/mol CO2, an initial absorption rate greater than
an initial desorption rate greater than
a cyclic capacity greater than
a lean loading of 0 at 110° C., a viscosity below 10 mPa·s at 30° C., and an alkalinity in the range of 9.5 to 11.0 pKa at room temperature.
Another aspect of the present invention relates to a method of performing carbon capture. The method comprises collecting flue gas from a flue gas emitting source and reacting the collected flue gas with the solvent described herein.
Other aspects of the present invention relate to systems for performing carbon capture. Preferably, such systems comprise components configured to perform methods of performing carbon capture using the solvents described herein. Other aspects of the present invention relate to an apparatus for performing carbon capture. Preferably, such apparatus comprises components configured to perform methods of performing carbon capture using the solvents described herein.
Another aspect of the present invention relates to the use of a solvent according to a preferred embodiment of the present invention, to perform carbon capture by collecting a flue gas comprising carbon dioxide from a flue gas emitting source and exposing the collected flue gas to said solvent for a period of time sufficient to remove at least a portion of said carbon dioxide gas present in said flue gas.
Additional aspects of the present invention will be apparent in view the description which follows.
Features and advantages of the embodiments of the present invention will become apparent from the following detailed description, taken in combination with the appended drawings in which:
The description which follows and the embodiments described therein are provided by way of illustration of an example or examples of particular embodiments of the principles of the present invention. In the following description of the invention, numerous examples are provided and specific details are set forth for the purposes of explanation and not limitation in order to provide a thorough understanding of the invention. The person skilled in the art will readily appreciate that the well-known methods, procedures and/or components will not be described as to focus on the invention in question. Accordingly, in some instances, certain structures and techniques have not been described or shown in detail in order not to obscure the invention.
It was determined that the performance of amines (e.g. their tolerance to amine degradation and the consequent emissions) in carbon capture processes can depend highly on the amine's functional groups and how they are placed in the amine structure. The chemical structural positioning of different functional groups in different amines and their effects on the rates of CO2 absorption and desorption, CO2 cyclic capacity, heat duty, amine degradation, off-gas emissions (specifically NH3), corrosion, and foaming were recorded and assessed. It was noted that the interaction of components in a given solvent can influence the overall performance of the solvent. Careful selection of various components of a given carbon capture solvent based on their possible interactions was undertaken to develop novel solvent systems which outperform known solvents used in carbon capture.
In light of the above knowledge and as described in more detail elsewhere herein, the inventors have formulated and reduced to practice solvent compositions that substantially outperform conventional solvents (e.g. 5M MEA) used in carbon capture applications. Unless context dictates otherwise, such solvent compositions may be referred to herein as solvents. The term solvent, as used herein, may be a compound or a blend or mixture of a plurality of compounds (i.e., a “solvent blend” or a “solvent mixture”). Carbon capture solvents as described herein typically comprise a first compound, which may be referred to herein as “Compound I”, and/or a second compound, which may be referred to herein as “Compound II”. The person skilled in the art will also understand that solvent is meant to refer to a liquid, more preferably a homogeneous liquid.
According to a preferred embodiment of the present invention, compound I is a tertiary amine, having a chemical formula of (R1)(R2)N(CnH2n—OH), where R1 and R2 are independently a linear or branched alkyl group with a carbon number between 1 to 6, preferably between 2 to 4, and n is an integer between 1 to 6, preferably between 2 to 4. According to a preferred embodiment of the present invention, compound I can be, for example, diethylaminoethanol.
As used herein, the term “diethylaminoethanol” or “DEAE” refers to a tertiary amine whose amino nitrogen is connected to two ethyl groups and one ethyl-amino group. Specifically, the two (2) ethyl substituents have electron donating property that provides extra electron density to the amino nitrogen of the molecule. The richness of electrons on the amino group reaction center can enhance the CO2 and amine reactivity. Thus, additional electrons supplied to the DEAE's amino nitrogen increases its reaction absorption rate with CO2. Advantageously, the absorption rate of DEAE is higher than that of the conventional tertiary amines such as MDEA whose molecule only contains a weaker electron donating methyl substituent.
Advantageously, DEAE also has a fast CO2 desorption rate. The fast desorption rate can also be attributed to the two ethyl substituents on the amine structure. Since, DEAE is a tertiary amine, bicarbonate (HCO3−) and carbonate (CO32−) are only formed from the absorption reaction. Due to the negative charges on the two anionic products, they are also attracted to the protonated amine generated also in the solution. Such attraction determines the desorption ability of the amine such that the weaker the electrostatic attraction between the charged species, the better and the faster the desorption rate. In the case of DEAE, the presence of the two (2) ethyl substituents with electron donating property weakens the ionic attraction. Electrons supplied to the protonated amine's nitrogen by the two (2) ethyl substituents repel the HCO3− and CO32. The repulsion leads to a molecular break-down of the two (2) ionic species which subsequently releases the CO2. In contrast, conventional tertiary amines such as MDEA do not have the same ability to weaken the attraction between its protonated constituent and the two (2) carbonates (i.e., due to a less efficient methyl group unable to provide the same electron density to the nitrogen, thus less effective desorption process).
According to a preferred embodiment of the present invention, compound II contains two primary amino groups, having a chemical formula of NH2— (CmH2m)—NH2, where m is an integer between 2 to 10, preferably between 4 to 8. According to a preferred embodiment of the present invention, compound II can be, for example, hexamethylenediamine.
As used herein, the term “hexamethylenediamine” or “HMDA” refers to a diamine whose molecule comprises two (2) primary amino groups connected to each other by six (6) carbons. Both primary amino groups in HMDA structure are able to provide the maximum of two (2) active sites for the CO2 absorption reaction to take place. This also implies that one (1) molecule of HMDA can take the maximum two (2) molecules of CO2. In comparison to convention primary amines such as MEA, the CO2 access to number of the reaction reactive site on MEA molecule is limited to one (1), thus absorption reaction occurs only on a one (1) molecule MEA per one (1) molecule CO2 basis. Hence, HMDA helps to increase the CO2 amount absorbed per cycle from that obtained from MEA.
According to a preferred embodiment of the present invention, carbon capture solvents described herein may also comprise one or more additional compounds in addition to Compound I and/or Compound II described above. For example, carbon capture solvents described herein may comprise polyethylenimine.
As used herein, the term “polyethylenimine” or “PEI” refers to a polymeric amine whose structure contains: (a) multi groups of primary, secondary, and tertiary amine encased in a branched polymeric structure; (b) multi groups of primary and tertiary amine encased in a branched polymeric structure; or (c) multi groups of secondary amine in a linear polymeric structure. Branched polyethylenimines with all of primary, secondary, tertiary amino groups are preferred in some embodiments of the present invention. The absorption characteristic of PEI benefits from its primary and secondary amino groups while secondary and tertiary amino groups facilitate its desorption of CO2. According to a preferred embodiment of the present invention, the PEI has up to fifteen (15) active amino groups that have affinity toward the CO2 in the absorption reaction. This implies that CO2 amount captured per amine molecule of PEI can far exceed those of conventional amines like MEA and MDEA whose CO2 capacities are known to limit to 0.5 and 1 respectively. Thus, CO2 capture capacity of PEI can be several-fold more than those of the single amines.
According to a preferred embodiment of the present invention, the carbon capture solvent comprises one or more of: diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), and polyethylenimine (PEI). For example, the carbon capture solvent blend may be an aqueous solution comprising one or more of: diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), and polyethylenimine (PEI).
In some embodiments, the solvent comprises DEAE with a molar concentration in the range of 2.0M to 4.0M (e.g., 2.0M, 2.05M, 2.10M, 2.15M, 2.20M, 2.25M, 2.30M, 2.35M, 2.40M, 2.45M, 2.50M, 2.55M, 2.60M, 2.65M, 2.70M, 2.75M, 2.80M, 2.85M, 2.90M, 2.95M, 3.00M, 3.05M, 3.10M, 3.15M, 3.20M, 3.25M, 3.30M, 3.35M, 3.40M, 3.45M, 3.50M, 3.55M, 3.60M, 3.65M, 3.70M, 3.75M, 3.80M, 3.85M, 3.90M, 3.95M, 4.00M, or any value therebetween).
In some embodiments, the solvent comprises HMDA with a molar concentration in the range of 0.10M to 1.00M (e.g., 0.10M, 0.15M, 0.20M, 0.25M, 0.30M, 0.35M, 0.40M, 0.45M, 0.50M, 0.55M, 0.60M, 0.65M, 0.70M, 0.75M, 0.80M, 0.85M, 0.90M, 0.95M, 1.00M, or any value therebetween).
In some embodiments, the solvent comprises PEI with a molar concentration in the range of 0.005M to 0.50M (e.g., 0.005M, 0.01M, 0.015M, 0.02M, 0.025M, 0.03M, 0.035M, 0.04M, 0.045M, 0.05M, 0.10M, 0.15M, 0.20M, 0.25M, 0.30M, 0.35M, 0.40M, 0.45M, 0.50M, or any value therebetween).
In some embodiments, the solvent comprises PEI having a molecular weight of between about 750 Da to about 850 Da (e.g., 800 Da). In some embodiments, the number of repeating units of the PEI in the solvent is about 1.5. In some cases, if the PEI's molar mass it too high, it may cause the solvent to be too viscous and suboptimal for carbon capture applications in some cases.
In some embodiments, the solvent has a total molar concentration of 5.5M or less (i.e., beyond which precipitation issues and phase separation issues may occur). In some embodiments, the solvent has a total molar concentration of about 4.0M (e.g., within ±0.01M). In some embodiments, the solvent comprises 3.6M DEAE, 0.4M HMDA, and 0.01M PEI (e.g., within ±0.001M for each of DEAE, HMDA, and PEI).
In some embodiments, the solvent has a lean loading of ˜0 at 110° C. (i.e., implying that the solvent can be used at relatively lower temperatures while achieving lean loadings close to 0).
In some embodiments, the solvent has a viscosity below 10 mPa·s at 30° C. (e.g., 9.5 mPa·s, 9.0 mPa·s, 8.5 mPa·s, 8.0 mPa·s, 7.5 mPa·s, 7.0 mPa·s, 6.5 mPa·s, 6.0 mPa·s, 5.5 mPa·s, 5.0 mPa·s, 4.5 mPa·s, 4.0 mPa·s, 3.5 mPa·s, 3.0 mPa·s, 2.5 mPa·s, 2.0 mPa·s, 1.5 mPa·s, 1.0 mPa·s, or any value therebetween at 30° C.).
In some embodiments, the solvent has an alkalinity in the range of 9.5 to 11.0 pKa at room temperature (e.g., 9.55 pKa, 9.60 pKa, 9.65 pKa, 9.70 pKa, 9.75 pKa, 9.80 pKa, 9.85 pKa, 9.90 pKa, 9.95 pKa, 10.00 pKa, 10.05 pKa, 10.10 pKa, 10.15 pKa, 10.20 pKa, 10.25 pKa, 10.30 pKa, 10.35 pKa, 10.40 pKa, 10.45 pKa, 10.50 pKa, 10.55 pKa, 10.60 pKa, 10.65 pKa, 10.70 pKa, 10.75 pKa, 10.80 pKa, 10.85 pKa, 10.90 pKa, 10.95 pKa, or any value therebetween at room temperature).
It was noted that functional groups that increase the electron density around the nitrogen reactive site can increase the CO2 absorption rate. In some instances, amines with multi amine groups were also recognized to increase CO2 absorption rate due to increased number of available nitrogen reactive sites. In addition, it was noted that the high number of amino groups increased the CO2 absorption capacity of the amines. Based on this knowledge, it was assessed that including a diamine such as HMDA in a solvent blend can provide the benefits of fast CO2 absorption kinetics.
It was surprisingly and unexpectedly discovered that PEI, a multi amine polymer, when included in a solvent blend, substantially improved solvent qualities for use in carbon capture and sequestration. According to a preferred embodiment of the present invention, a branched PEI with about fifteen (15) amine groups increased the CO2 absorption kinetics and the CO2 carrying capacity of the solvent blend. PEI is a very viscous amine and can be preferably used at concentrations at and below about 0.3M.
According to a preferred embodiment of the present invention and in order to tackle the desorption aspect of the solvent blend, a component with a high performing desorption ability was incorporated into the solvent. It was recognized that tertiary amines, which are typically known to have high desorption performance, have low absorption performance due to the absence of a hydrogen atom on the central nitrogen atom. In view of this, a tertiary amine whose structure can allow it to absorb CO2 faster than a traditional tertiary amine would was incorporated into the solvent. It was determined that the presence of the two ethyl groups substituted on the central nitrogen atom increases its electron density, and hence its reactivity towards CO2. To achieve this, DEAE, a compound having a very high stripping ability and a suitable structure, was incorporated as part of the solvent blend. Owing in part to its relatively less viscous nature, DEAE can be used in relatively higher concentrations to provide a synergistic benefit to the overall mixture based on its unique characteristics.
According to a preferred embodiment of the present invention, a solvent described herein provides improved performance over conventional solvents used in carbon capture processes. For example, some solvent blends described herein provide an initial CO2 absorption rate that is up to about 37% higher than that of convention MEA solvents (e.g., Solvent 23 described below had a higher initial CO2 absorption rate than 5M MEA). As another example, some solvent blends described herein provide an initial CO2 desorption rate that is up to about 3.85 times higher than that of conventional MEA solvents. As another example, some solvent blends described herein provide cyclic capacity that is up to about 85% higher than that of convention MEA solvents. As another example, some solvent blends described herein have much lower NH3 emission rates than those of convention MEA solvents.
Other additional non-limiting advantages provided by preferred solvents described herein are described in more detail below with reference to certain specific properties of other known compositions:
While HMDA has been proposed for use in applications related to carbon capture, existing technologies are limited to using HMDA in association with solid sorbents, using HMDA in a biphasic scrubbing solution, and using HMDA as a cluster stabilizer.
While PEI has been proposed for use in applications related to carbon capture, existing technologies are limited to using PEI in amine solid sorbent for CO2 adsorption (e.g., using PEI as part of the carbon capture layer where the amine is functionalized on to solid materials such as graphene oxide or non-porous carbon).
Another aspect of the invention provides a method of carbon capture using solvents described herein.
After reacting the collected flue gas with the solvent in step 1100, method 100 may, in some embodiments, proceed to one or more of the following optional steps (not shown): a step of regenerating the solvent blend by stripping away the captured CO2 from the rich solvent, a step of releasing the clean flue gas into the atmosphere, a step of injecting the stripped CO2 into a geological formation, etc.
Other aspects of the invention include systems and/or apparatuses that may be configured to implement carbon capture methods of the kind described above.
In addition to the exemplary aspects described above, the present invention is further described in the following Examples, which are set forth to aid in the understanding of the invention, and should not be construed to limit in any way the scope of the invention as defined in the claims which follow thereafter.
The viability of different solvents for use in carbon capture processes was assessed. In the experiments, various aqueous amine solutions were prepared to a desired condition by mixing predetermined mass of the amine/amines with deonized water. The amine/amines comprised one or more of the following compounds: 2-diethylaminoethanol (DEAE), hexamethylenediamine (HMDA), polyethylenimine (PEI, branch), 2-dimethylaminoethanol (DMAE), and monoethanolamine (MEA).
In the experiments, 1M hydrochloric acid (HCl, Fisher Chemical) was used for titration with methyl orange as an indicator to confirm the concentration of the amine solution and the solution's CO2 loading. In the experiments, Sulfuric acid (H2SO4, >67%, Fisher Chemical) was used to prepare the impinger solution for collection of NH3 in off-gas released from the amine degradation reaction. Research grade of 100% CO2, 100% O2, air, and 100% N2 were all industrial grade and supplied from Linde (Regina, Saskatchewan, Canada). The desired feed gas concentration used in the experiments was obtained by the inventors by mixing predetermined volumetric flow rates of individual gases needed for such experiment which were adjusted and controlled by mass flow meters (Cole-Parmer, Canada). Final concentrations of all constituents in the mixed gas stream were confirmed by the inventors using infrared based multi-gas analyser (Nova Analytical Systems, Canada).
The compositions of the solvents used in the experiments are shown in Table 1 below:
Table 1: Shows the composition of the solvents used by the inventors to perform experiments
The CO2 absorption rate of the solvents was evaluated and listed in Table 1. The CO2 absorption rate was evaluated by performing experiments using the apparatus shown in
At the beginning of each absorption experiment, a prepared amine solution of 150 ml contained in the flask was fully immersed in the oil bath in order for the amine solution to reach the temperature of 40 ±° C. The gas (4% CO2 and 96% N2) was then bubbled into the solution through the gas dispersion tube at a constant flow rate of 300 ml/min (±2 accuracy). Samples were then taken at regular intervals of 10 min for the first 1 hour, and then 30 min interval until at the end of 9 hours. The final loading recorded at the 9th hour was taken as the rich loading. Samples were analyzed using the Chittick apparatus to obtain the CO2 loading at each time period, and a plot of CO2 loading versus time was generated based on the data.
The slope of the linear section of the absorption profile was used to establish the initial absorption rate (mol CO2/L·solution), which is essentially the slope multiplied by the total amine concentration. The initial absorption rate is calculated by multiplying the slope by the amine concentration. For example, the Absorption Profile of 5M MEA is shown in
The CO2 absorption rate and rich loading of the various different solvents is listed in Table 2 below.
The CO2 desorption rate of the solvents was also evaluated and listed in Table 1. In the desorption experiment, a known volume (76 ml) was measured from the rich amine solution obtained from the absorption experiment. The same setup used for the absorption experiment was used for this experiment. However, in this experiment the gas dispersion tube shown in
The initial desorption rate was calculated by determining the slope of the linear section of the desorption as most of the removable CO2 had been removed within that section. For example, the Desorption Profile of 5M MEA is shown in
The CO2 desorption rate of the various different solvents is listed in Table 2 below.
For each of the various solvents listed in Table 1, the heat duty of the solvent based on the heat rate and the CO2 desorption rate was determined. The heat duty was calculated by determining the ratio of the steady state heat transfer to the amount of CO2 removed during desorption over a 5 min period (i.e., the linear portion of the desorption kinetics profile). Using Fourier's equation of molecular heat transport to calculate the heat supplied from the oil bath as shown in Equation (3):
For example, the Heat Duty for baseline 5M MEA is calculated as follows:
The heat duty of the various different solvents is listed in Table 2 below.
For each of the solvents listed in Table 1, the cyclic capacity of the solvent based on the rich loading, the lean loading, and the molar concentration of the amine was determined. The cyclic capacity refers to how much CO2 has been removed in a cycle. The cyclic capacity is calculated using Equation (5):
For example, the Cyclic Capacity for 5M MEA is calculated as follows:
The cyclic capacity of the various different solvent blends is listed in Table 2 below.
Table 2: Shows the performance indicators of the solvents used by the inventors to perform experiments described herein
The primary performance indicators used in these experiments are initial absorption rate, cyclic capacity, initial desorption rate and heat duty. In the course of the testing, two other factors were added—the precipitation and phase separation of amine solution after being loaded with CO2.
These two additional factors are very important as each may cause operational issues such as pipe clogging, equipment fouling and increased pumping power requirement during the CO2 capture process.
From the experiments, it was observed that Solvents 1, 3 and 4 had a higher absorption performance (absorption rate and rich loading) as well as a higher desorption rate and lower heat duty than the baseline MEA. Overall, these solvents have better performance than the baseline MEA. However, after loading with CO2 and being left standing for a day, Solvents 1, 3 and 4 precipitated.
It was also observed that Solvents 10, 11, 12, 14 and 15 outperformed the baseline MEA in all aspects. As shown in Table 2, these solvents had higher absorption rates, higher rich loading, higher desorption rates, higher cyclic capacities and lower heat duties when compared with MEA. Although these solvents had good performance, phase separation of the rich-loaded solutions after the end of the absorption experiment was observed.
For Solvents 2, 5, 6, 7 and 8, the absorption rates for solvents in this category were observed by the inventors to be lower or similar to that for MEA. With the exception of Solvent 6, the rich loadings for these solvents were similar to or higher than that of MEA. The desorption rates, cyclic capacities and heat duties for these solvents were all lower than MEA, except Solvent 5, which had a higher desorption rate and cyclic capacity as well as a lower heat duty than that of MEA (e.g., see Table 2). Solvents in this category contained DMAE, whose boiling point is 133° C. Considering the desorption temperature used for this experiment as well as the typical operational temperature range of desorption (110° C.-120° C.), it was hypothesized that using DMAE may lead to high amine losses due to its boiling point.
Solvent 9 was observed to have a relatively lower performance than MEA. Solvent 13, on the other hand, was observed to have better performance than the baseline MEA as shown in Table 2. Solvents in this group had a total concentration ranging from 2M-3M. Using low amine concentration would require higher solvent circulation rates.
Aside from having lower rich loadings than MEA, Solvents 20 and 21 were observed to have significantly higher desorption rates, cyclic capacities and significantly lower heat duties than MEA (e.g., see Table 2). A high rich loading becomes useful when the amine is able to easily desorb a significant amount of CO2. It is worth mentioning that even though solvents in this group had lower rich loading than MEA, due to their high stripping ability, the amount of CO2 that is removed is higher than that for MEA, whose rich loading is high, but whose CO2 desorption rate/stripping ability is lower.
Solvent 16 was observed to have a rich loading lower than MEA. However, in terms of the other performance indicators, this solvent outperformed MEA. In terms of the absorption rate, Solvent 16 had an absorption rate 37% higher than MEA. For cyclic capacity, Solvent 16 was 66% higher than MEA. In terms of the desorption rate, Solvent 16 was ˜3.7 times that of MEA whereas the heat duty for this solvent was ˜3.7 times lower than MEA (e.g., see Table 2). The lean loading obtained for this solvent is very close to zero unlike that for MEA.
Solvent 17 was adjusted to increase the contribution of HMDA in the formula, in order to enhance the absorption rate. PEI was added to increase the absorption capacity as well as the absorption rate. The results show that the absorption rate for this solvent was 14% higher than MEA. However, its rich loading was lower than MEA. In terms of desorption, its desorption rate was ˜3.8 times that of MEA. In terms of heat duty, its heat duty was ˜3.8 times lower than that of MEA. With a lean loading approximately zero, its cyclic capacity was 76% higher than that of MEA (e.g., see Table 2). The contributions of HMDA and PEI were not clearly noticeable, mainly due to the fact that the concentration was higher, thereby increasing the mass transfer limitation as well. However, increasing the concentration of DEAE in the formula enhanced the desorption rate as well as the cyclic capacity.
Solvent 18 was adjusted to increase the concentration of PEI while maintaining a total concentration of 5M and a DEAE/HMDA ratio of 9. It was noted that this adjustment did not help the absorption but rather decreased the desorption performance when compared with Solvent 17. The results for this solvent still show higher performance than the baseline solvent MEA. In terms of the absorption rate, solvent 18 is 14% higher than MEA, desorption rate ˜3.5 times that of MEA and its heat duty is ˜3.5 times lower than MEA as well as its cyclic capacity 76% higher than that of MEA (e.g., see Table 2).
Solvents 19 was adjusted to further increase the concentration of PEI while maintaining a total concentration of 5M and a DEAE/HMDA ratio of 9. It was noted that this adjustment did not help the absorption but rather decreased the desorption performance when compared with Solvent 17. The results for this solvent still show higher performance than the baseline solvent MEA. The cyclic capacity on the other hand increased a bit when compared with solvent 18. In terms of the absorption rate, solvent 19 is 14% higher than MEA, desorption rate ˜3.6 times that of MEA and its heat duty is ˜3.6 times lower than MEA as well as its cyclic capacity 85% higher than that of MEA (e.g., see Table 2).
Solvent 22 comprised 3.85M DEAE, 0.15M HMDA and 0.015M PEI. There was no significant improvement. The results show that solvent 22 had an absorption rate 14% higher than MEA, desorption rate ˜3.6 times MEA, heat duty ˜3.6 times lower than MEA, cyclic capacity 66% higher than MEA (e.g., see Table 2).
Solvent 23 comprised 3.6M DEAE, 0.4M HMDA and 0.01M PEI. The DEAE/HMDA ratio established in this solvent is similar to that of the ratio in Solvents 17, 18 and 19. The concentration was reduced to 4M in order to reduce mass transfer limitations, and to be able to see the synergistic benefit of the constituents in the blend. The results show that Solvent 23 had the highest performance in all aspects relative to all other solvents as well as the baseline MEA. For the initial absorption rate, Solvent 23 was 37% higher than MEA; for initial desorption rate it was ˜3.85 times that of MEA; for cyclic capacity it was 85% higher than MEA and the heat duty was ˜3.85 times lower than MEA (e.g., see Table 2).
Solvent 24 comprised 3.6M DEAE, 0.4M HMDA and 0.015M PEI. The concentration of PEI in the blend was increased from 0.01M, as compared to Solvent 23, to 0.015M. The results show that increasing the concentration of PEI did not improve the performance. For the initial absorption rate, Solvent 24 was 37% higher than MEA; for initial desorption rate it was ˜3.64 times that of MEA; for cyclic capacity it was 85% higher than MEA and the heat duty was ˜3.64 times lower than MEA (e.g., see Table 2).
Solvent 25 comprised 3.6M DEAE and 0.4M HMDA. For the initial absorption rate, Solvent 25 was 26% higher than MEA; for initial desorption rate it was ˜3.77 times that of MEA; for cyclic capacity it was 85% higher than MEA and the heat duty was ˜3.77 times lower than MEA (e.g., see Table 2).
A method of measuring the performance of the various solvents was developed. The method involved combining the various performance criteria into an absorption parameter and a desorption parameter that can account for the absorption performance as well as the desorption performance. The absorption parameter was defined as the absorption rate (10−2 mol CO2/L·soltn). The desorption parameter was defined as a combination of the desorption rate, the cyclic capacity and the heat duty as set out in Equation (6):
Experiments were carried out to assess ammonia emissions of several solvents listed in Table 1.
To assess off-gas emissions of the amines, gaseous NH3 evolving from the reaction was also collected from the off-gas produced from the possible degradation reaction. The outlet of the condenser attached directly to the reaction flask was connected to the inlet of the impinger bottle filled with 50 mL of 0.05 M H2SO4 to trap the NH3 formed from the amine degradation reaction. The impinger bottle was kept in an ice bath the whole time during sampling to ensure that all the NH3 released was being fully collected in the impinge solution. The outlet of the impinger was also connected with the rotameter and then vacuum pump set at 200±2 mL/min similar to that set for the feed gas flow rate. The match of the two (2) flow rates was needed to prevent the NH3 from being under/over sampled. The sampling continued for one hour after which the impinger was disconnected completely from the condenser outlet. The impinger solution was then transferred into a 100 mL volumetric flask. A fresh 0.05M H2SO4 solution was also used to rinse the impinger bottle which was then poured back into the 100 mL flask. The flask was finally topped with the H2SO4 to 100 mL mark. The NH3 was collected at different time intervals starting at the first, third, fifth, 24th and 27th hour after which the collection was done once a day for 14 days. The collected samples were placed in the refrigerator before sending for analysis using the Ammonia/Nitrate Analyzer (Timberline Model TL-2800).
The mixture containing only 3.6 mol/L DEAE+0.4 mol/L HMDA emitted between 4 to 22 ppmv of NH3 which was also the same as those of the blended amines tested in this experiment. The single amines comprising 1 mol/L HMDA and 1 mol/L DEAE were also tested with their NH3 emission profiles included in
The viscosity, density, thermal conductivity and heat capacity were measured for different solvents (i.e., the high performance solvents) for the unloaded, loaded and mid-loaded samples at a temperature range of 30° C.-50° C. as shown in Tables 3-5 below.
A Digital Anton Paar micro viscometer model (Lovis-2000 M/ME) was used to measure the viscosities in mPas. This micro viscometer works by using the rolling ball principle which employs three inductive sensors to measure the time it takes for the ball to move through the liquid filled capillary. High quality deionized water was used to calibrate the equipment after each run. Prior to each measurement, the sample was kept inside the viscometer until the set temperature reached equilibrium condition. The accuracy was within 0.5% for viscosity and ±0.02° C. for temperature.
Densities were measured using DMA 4500M from Anton Paar with an accuracy of 0.00001 g/cm3 for density and 0.01° C. for temperature. Prior to using the equipment for measurements, air and water checks were done in order to validate and calibrate the equipment. High quality deionized water was used to calibrate the equipment after each run. Prior to each measurement, the sample was kept inside the viscometer until the set temperature reached equilibrium condition.
A thin platinum wire was immersed in the amine sample and measured the heat resistance profile of wire is with respect to time. A temperature-time profile of the amine samples was generated. These plots were used to determine thermal conductivity, thermal diffusivity, and heat capacity. Thermal conductivity and diffusivity were measured specifically at the beginning when temperature become stable, and then using the correlation of thermal diffusivity and heat capacity (D=K/(ρ Cp)), heat capacity will be computed at different time intervals. It should be noted that measurement of heat capacity required an input of predetermined density values of the sample at 3-4 temperatures for the software to be able to plot the density-temperature profile for later computation of heat capacity at different temperatures. These were provided using density data obtained from the density measurement. At least 3 repeated measurements of thermal properties were taken for each sample which their averaged values were used and reported.
Table 3 below shows the density of various amine solvents at 30° C., 40° C. and 50° C.
Table 4 shows the viscosity of various amine solvents at 30° C., 40° C. and 50° C.
Table 5 shows the thermal conductivity, diffusivity and heat capacity of various solvents at 30° C., 40° C. and 50° C.
Pilot plant testing was carried out in order to be able to assess the performance of a solvent according to a preferred embodiment of the present invention against a commonly used solvent, MEA. Solvent 23 (3.6M DEAE+0.4M HMDA+0.01M PEI) and MEA were run at full cycle in the pilot plant, mimicking close to real conditions.
The results of CO2 capture performance of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent obtained from a full absorption-desorption cycle pilot plant. The performance runs for 3.6M DEAE+0.4M HMDA+0.01M PEI solvent were carried out at 110° C. and 120° C. and compared with 5 MEA solvent also run using the same pilot plant and conditions as was used for 3.6M DEAE+0.4M HMDA+0.01M PEI solvent. This test of MEA was carried out so that its performance could be used to compare with 3.6M DEAE+0.4M HMDA+0.01M PEI solvent at the same temperature.
At the beginning of each run, the amine solution of the desired concentration and flow rate is pumped from the storage tank via the variable-speed gear pump to the top of the absorber. Meanwhile, the heater is switched on and set to the desired set point temperature which is used to heat up the rich amine from the absorber prior to entry into the desorber. Once amine solvent circulation is set, a mixture of CO2, N2 and air gases at the selected CO2 partial pressure and concentration is then introduced to the bottom of the absorber column through the gas flow meter, which controls the gas flows individually.
This allows for the gas to contact the down flowing liquid amine in a countercurrent manner. Treated gas leaves the top of the column, while the rich amine solvent leaves the absorber bottom and is preheated by the hot lean amine stream (coming from the bottom of the desorber) before re-entering the desorber for desorption of CO2. CO2 is desorbed from the rich amine in the desorber by heat supplied from the heater (reboiler). The lean amine, which now leaves the bottom of the desorber, is cooled by lean-rich heat exchanger and the cooler and fed into the absorber column for the cycle to continue.
The CO2 product gas at the top of the desorber is cooled by the condenser to remove any entrained water/amine and is dry before vented to the air. When the system has reached steady state, both the rich and lean amine samples are taken for CO2 loading analysis using titration and CO2 displacement technique. The temperature profile readings are also taken along the height of the absorber column using J-type thermocouples which are installed along the height of the column. The performance of the solvent used in the run is presented in terms of CO2 production rate, absorber efficiency, heat duty, gas and liquid mass transfer coefficients.
The plant was designed for a flow rate of 25 SLPM of feed gas containing 15% CO2. The liquid flow rate of amine was set at 50 mL/min. The conditions used for both run temperatures were feed gas flow rate of 25 SLPM and liquid amine flow rate of 50 mL/min. The CO2 concentration in flue gas was 4% which was one quarter of the CO2 concentration used to design the plant. The implication is that the volume of amine available is capable of absorbing all of CO2 at 4% based on the height of the column. So, for some criteria, it may not be easy to explicitly separate the performance of MEA and the 3.6M DEAE+0.4M HMDA+0.01M PEI solvent (most gas phase parameters such as off-gas concentration and absorber efficiency would be affected). To take into account various limitations such as the set up and the heating medium, the experiments were carried out at a pressure of 5 psi in the desorber when running at a desorption temperature of 110° C. and at a pressure of 10 psi in the desorber when running at 120° C. Due to the different operating pressures for the two regeneration temperatures it is inappropriate to compare the true effect of temperature on the performance of each solvent due to the extra parameter, pressure, that is added. Operating at a higher desorption pressure limits the desorption process and as a result, this effect leads to an overall lower performance observed in both 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA at the higher pressure at 120° C. when compared with 110° C. Thus, within this scope of work the comparison was limited to that between 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA at the same temperature. Table 6 shows the run conditions used for the tests.
Table 6 shows a summary of run conditions for 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA solvents
Table 7 summarizes performance run parameters used for comparing the 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA solvents at 110° C. The values for 3.6M DEAE+0.4M HMDA+0.01M PEI solvent at this temperature were averaged values from 2 repeated run while those for MEA were obtained from one test. Results at 120° C. for 3.6M DEAE+0.4M HMDA+0.01M PEI solvent are also given in Table 8.
Each test was conducted for more than 24 hr. This was to ensure that the run was stable and reached equilibrium before any measurements were taken. This condition was ensured for both solvents. Table 7 and 8 respectively summarize performance run parameters for 110° C. and 120° C. for 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA solvents.
Table 7 shows a summary of performance run parameters at 110° C. for 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA.
Table 8 shows a summary of performance run parameters at 120° C. for 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA.
Absorber efficiency can be calculated accurately based on both gas and liquid measurements. The gas side efficiency is shown by the percent difference of the amounts of CO2 entering and leaving the absorber. The liquid side efficiency on the other hand, is determined based on the amount of CO2 absorbed and released from the amine solvent (rich and lean CO2 loadings) compared to the total CO2 amount from the feed gas entering the absorber. Although two methods of calculation could be used, absorber efficiencies of all 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA runs at 110° C. and 120° C. were only taken from liquid side measurement which were accurate. Direct measurement from gas side efficiency for both solvents were not included due to insufficient data points of off-gas CO2 concentration used to obtain amount of CO2 leaving the absorber for calculation. When such data were used to determine absorber efficiency, there was very high uncertainty in the value that was obtained. Therefore, absorber efficiency determined based on direct gas measurement was not used. The absorber efficiency was calculated using Equation (7):
∝r, rich loading, mol CO2/mol amine
∝l, lean loading, mol CO2/mol amine
[Amine], Amine concentration, mol amine/L·soltn
Amine, Amine circulation/flow rate, L/min
yCO
G, Feed Gas flow rate, L/min
Based on Table 7, absorber efficiencies of 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA at 110° C. are 93.90% and 83.71%. This represents a 12% increase of the absorber efficiency when 3.6M DEAE+0.4M HMDA+0.01M PEI solvent was compared with MEA solvent. A higher absorber efficiency obtained for 3.6M DEAE+0.4M HMDA+0.01M PEI solvent implies having a huge opportunity to use a shorter absorber than with MEA. From Table 8, absorber efficiencies of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA at 120° C. are 86.32% and 76.11%; this represents 13% increase of the absorber efficiency when 3.6M DEAE+0.4M HMDA+0.01M PEI solvent was used in comparison with MEA solvent.
Mass transfer coefficient were calculated based on both liquid and gas phases. The gas phase mass transfer coefficient (KGav) calculation is done based on two CO2 concentration data points which are those of CO2 entering (from feed gas concentration) and leaving (from absorber off-gas) the absorber column. The liquid phase mass transfer coefficient (KLav) on the other hand, is determined based on the amount of CO2 absorbed and desorbed from the amine solvent (from rich and lean CO2 loadings). As mentioned previously, absorber off-gas CO2 concentration data were not sufficiently high enough to allow KGav to be accurately calculated directly. To calculate the KGav values of both 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA with accuracy, liquid phase absorber efficiencies determined respectively for 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA were first used to obtain the corresponding average CO2 concentration in the absorber off-gas for both solvents. The off-gas CO2 concentrations were then further used together with all other data measured directly from the tests to calculate the values of KGav.
As seen in Table 7, KGav of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA solvent determined based on liquid side efficiency are 0.79 and 0.47 kmol/hr·m3·kPa, respectively at 110° C. This shows 68% enhancement of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent relative to MEA. From Table 8, the KGav of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA are 0.55 and 0.38 kmol/hr·m3·kPa, respectively at 120° C. This represents a 45% enhancement of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent relative to MEA. The enhancement from the mini plant test is also consistent with the enhancement of absorption parameter used previously to evaluate 3.6M DEAE+0.4M HMDA+0.01M PEI solvent relative to MEA in the screening test (given in the previous report). The KGav of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent being higher than that of MEA indicates the 3.6M DEAE+0.4M HMDA+0.01M PEI solvent's ability to remove CO2 more effectively and quickly. This also means, for a given height of absorber tower, 3.6M DEAE+0.4M HMDA+0.01M PEI solvent should be able to remove more CO2 more quickly than MEA. This also suggests that the 3.6M DEAE+0.4M HMDA+0.01M PEI solvent should require a shorter absorber column to remove the same amount of CO2 as MEA would in a longer absorber column.
KLav of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent, on the other hand, is overwhelmingly larger than that MEA with the values being 2.72 hr− and 0.52 hr− at 110° C. and 2.33 hr− and 0.49 hr− as can be seen in Tables 7 and 8. The KLav enhancement obtained from 3.6M DEAE+0.4M HMDA+0.01M PEI solvent relative to MEA is remarkably high which is 426% and 325% at 110° C. and 120° C., respectively. Similar to KGav, the same order of magnitude of KLav enhancement produced by 3.6M DEAE+0.4M HMDA+0.01M PEI solvent was also observed from the screen test. This clearly shows an excellent CO2 absorption and desorption ability of 3.6M DEAE+0.4M HMDA+0.01 M PEI solvent that MEA does not have to the same extent. This result suggests that if a CO2 plant being designed with 4 absorber per 1 desorber for an MEA system, with 3.6M DEAE+0.4M HMDA+0.01 M PEI solvent, that same 1 desorber can handle the quadruple of the number of absorbers MEA would have handled, suggesting that the 3.6M DEAE+0.4M HMDA+0.01 M PEI solvent with the same 1 unit desorber can handle 16 absorbers instead. The equations used for KGav and KLav are shown in the following equations, Equation (8) and Equation (9):
Where, G1 is the molar inert-gas flow rate (kmol/hr),
P is the column pressure, (kPa),
yCO2, mole fraction of CO2 in the bulk gas
y*CO2, mole fraction of CO2 in the bulk gas in equilibrium with the liquid bulk
YCO2in, mole ratio of CO2 in
YCO2out, mole ratio of CO2 out
Where
xAL_T, is the mole fraction of CO2 in the liquid bulk entering the desorber top,
xAL_B is the mole fraction of CO2 in the liquid bulk leaving the desorber bottom,
Z is the column height, m
CAL, the average CO2 concentration in the liquid bulk, kmol/m3
xAL, is the average mole fraction of CO2 in the liquid bulk
CA*, CO2 concentration in the liquid in equilibrium with the bulk gas
CO2 production can be calculated based on gas and liquid measurement. The gas side calculation is normally calculated based on the CO2 concentration difference between that of feed gas and absorber off-gas and flow rate of gas. Similar to absorber efficiency and gas side mass transfer analysis, the direct measurement on gas side did not have enough data. Thus, liquid side efficiency was used to first obtain the averaged CO2 concentration in the absorber off-gas which was then used in CO2 production calculation. The liquid side CO2 production calculation is straightforward and determined from using the difference between rich and lean CO2 loading and the amine flow rate. CO2 production from gas and liquid sides of 3.6M DEAE+0.4M HMDA+0.01M PEI and MEA solvent are 131 and 117 g/hr, respectively at 110° C. and 112.5 and 99.4 g/hr at 120° C., representing a 12% enhancement. This is again due to the 3.6M DEAE+0.4M HMDA+0.01M PEI solvent's desorption ability that enables the solvent to release CO2 almost completely during the desorption process. It is noteworthy to mention that even at a temperature of 110° C. 3.6M DEAE+0.4M HMDA+0.01M PEI solvent had a lean loading approximately close to zero. Operating at a higher temperature, 120° C. did not impact the lean loading of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent in any way. As such, it is recommended to operate at 110° C., suggesting savings in energy.
Reboiler duty was determined from the difference in silicone oil temperatures entering and leaving the reboiler, heat capacity (CP), and flow rate. Based on the two solvents' runs, their reboiler duties were approximately the same, thus average was taken and used for heat duty calculations of both solvents. Heat duties without heat loss reported as heat duty (based on liquid side) in Tables 7 and 8 were calculated based on reboiler duty divided by each amine's CO2 amount removed from feed gas obtained from liquid analysis (rich and lean CO2 loadings). Heat duties of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA are 15.1 and 16.93 GJ/tonne CO2, respectively at 110° C. and 20.41 and 18.03 GJ/tonne CO2 at 120° C. These values corresponds to 11%-12% reduction (for the two temperatures) of heat duty when 3.6M DEAE+0.4M HMDA+0.01M PEI solvent was used in place of MEA. Heat duty on gas side (based on direct measurement) was not reported due to inadequacy of CO2 off-gas concentration data explained previously.
Attempts to measure heat loss during the experiment were made so that heat duty described earlier could be adjusted so that the values would reflect closer to the actual heat duty value each amine could actually provide in a real commercial capture process. However, at this stage of the test, only heat loss around the reboiler could be estimated with acceptable accuracy. Other areas of heat losses were not performed. As can also be seen in Table 7 and 8, heat loss related to reboiler was estimated to be 1079 kJ/hr and 2111 kJ/hr at 110° C. and 120° C., respectively. The heat losses were then used to adjust the heat duty requirement of 3.6M DEAE+0.4M HMDA+0.01M PEI solvent and MEA solvent accordingly. If heat losses from other areas were also included in the heat duty calculation, it would result in even small heat duties for the two amines which would be closer to their actual values. The reboiler duty and heat duty were calculated based on the following equations, Equation (10) and Equation (11):
Reboiler Duty,kJ/hr=m*Cp*(Toil in−Toil out), (10)
Where m is the mass flow rate of the oil, kg/hr
Cp is the heat capacity of the oil, kJ/kg° C.
Toil in, is the oil inlet temperature, ° C.
Toil in is the oil inlet temperature, ° C.
The examples and corresponding diagrams used herein are for illustrative purposes only. The principles discussed herein with reference to determination of equilibrium dissociation constants can be implemented in other systems and apparatuses. Different configurations and terminology can be used without departing from the principles expressed herein. For instance, steps, equipment, components, and modules can be added, deleted, modified, or re-arranged without departing from these principles
Unless the context clearly requires otherwise, throughout the description and the claims: “comprise,” “comprising,” and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense; that is to say, in the sense of “including, but not limited to”. “Herein,” “above,” “below,” and words of similar import, when used to describe this specification shall refer to this specification as a whole and not to any particular portions of this specification. “Or” in reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list. The singular forms “a”, “an”, and “the” also include the meaning of any appropriate plural forms.
Where a component is referred to above, unless otherwise indicated, reference to that component should be interpreted as including as equivalents of that component, any component which performs the function of the described component (i.e., that is functionally equivalent), including components which are not structurally or compositionally equivalent to the disclosed structure or composition which performs the function in the illustrated exemplary implementations of the invention.
Specific examples of compositions, systems, methods and apparatuses have been described herein for purposes of illustration. These are only examples. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes variations on described compositions that would be apparent to the skilled addressee, including variations obtained by: replacing features, elements and/or chemical compounds with equivalent features, elements and/or chemical compounds; mixing and matching of features, elements and/or chemical compounds from different examples; combining features, elements and/or chemical compounds from examples as described herein with features, elements and/or chemical compounds of other technology; omitting and/or combining features, elements and/or chemical compounds from described examples.
It is therefore intended that the following appended claims and claims hereafter introduced are interpreted to include all such modifications, permutations, additions, omissions and sub-combinations as may reasonably be inferred. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole.
This application claims the benefit of and priority to U.S. Provisional Application No. 63/235,802, filed Aug. 22, 2021. The entire specification and figures of the above-referenced application are hereby incorporated, in their entirety by reference.
| Number | Date | Country | |
|---|---|---|---|
| 63235802 | Aug 2021 | US |
