JP2022076367A - Carbon recovery solvent with alcohol and amine and using method of the solvent - Google Patents

Abstract

To provide an improved solvent for absorbing and separating CO2 from an exhaust gas.SOLUTION: A solvent can contain 2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol and an aqueous mixture of potassium carbonate or buffer salt of potassium carbonate. The solvent may contain dissolution medium (that is, water) of less than about 75 wt.% and may have a single liquid phase. The solvent and a method have desirable regeneration energy, chemical stability, vapor pressure, total heat consumption, net circulation volume and reaction kinetics.SELECTED DRAWING: Figure 1

Description

This application generally and more specifically relates to carbon recovery.

Separating CO ₂ from gas streams has been commercialized for decades in food production, natural gas sweetening, and other processes. Aqueous monoethanolamine (MEA) -based solvent recovery is currently considered to be the best commercially available technology for separating CO ₂ from exhaust gases, and future developments in this area are being evaluated. It is a benchmark to do. Unfortunately, amine-based systems were not designed to handle the large amounts of flue gas produced at pulverized coal power plants. Scaling an amine-based CO ₂ capture system to the size required for such a plant is estimated to result in an 83% increase in overall electricity costs for such plant.

Therefore, an improved solvent is always needed.

The embodiments described herein include, for example, compounds and compositions, as well as methods of making and using compounds and compositions. Systems and devices related to methods using these compounds and compositions may also be provided. For illustration purposes, the present disclosure relates to a carbon recovery solvent (eg, named "APBS") and a method for treating industrial exhaust gas using that solvent. The solvents disclosed herein remove CO ₂ at a slower rate than MEA and degrade at a slower rate than other solvents (eg, MEA).

In one embodiment, the compositions and methods disclosed herein can be implemented in various types of industrial plants, including, for example, power plants. In one example, the solvent may include an aqueous mixture of 2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and a potassium carbonate buffer. .. The composition may also contain less than about 75% by weight of the dissolution medium (ie, water) and may have a single liquid phase. In another example, the solvent may include an aqueous mixture of amino hindered alcohols, polyamines having three or more amino groups, and carbonate buffers.

Additional features of this disclosure will be apparent to those of skill in the art by reviewing the following detailed description illustrating the best embodiments for carrying out the disclosure.

Embodiments of devices, systems, and methods are shown in the illustrations of the accompanying drawings, which means they are exemplary and not limiting, and similar references are intended to refer to similar or corresponding parts. It is a thing.

FIG. 1 shows APBS vapor-liquid equilibrium data at 40 ° C. and 120 ° C. for determining CO ₂ loading (mol / L) vs. CO ₂ partial pressure (kPa).

FIG. 2 shows APBS solvent-gas-liquid equilibrium data compared to MEA according to the present disclosure.

FIG. 3 shows the flow scheme of the carbon recovery pilot according to the present disclosure.

FIG. 4 shows the corrosion / solvent metal content of MEA (30% by weight) and APBS according to the present disclosure.

FIG. 5 shows ammonia emissions during a pilot plant campaign according to the present disclosure.

FIG. 6 shows the particle size distribution of the aerosol according to the present disclosure.

FIG. 7 shows the effect of the L / G ratio on the reproduction efficiency according to the present disclosure.

FIG. 8 shows the effect of stripper pressure on regeneration efficiency according to the present disclosure.

FIG. 9 shows methane recovery using the solvent according to the present disclosure.

Definitions As used herein, the term "solvent" may refer to a single solvent or a mixture of solvents and may be used interchangeably with the term "composition".

A detailed description of aspects of the present disclosure described herein will be by reference to the accompanying drawings and photographs illustrating various embodiments. These various embodiments have been described in sufficient detail to allow one of ordinary skill in the art to carry out the disclosure, but other embodiments can be realized and the logical and mechanical changes are disclosed. Please understand that it can be done without departing from the spirit and scope of. Therefore, the detailed description herein is presented for purposes of illustration only, not limitation. For example, the steps described in any of the methods or process descriptions can be performed in any order and are not limited to the presented order. Further, a reference to a single embodiment may include a plurality of embodiments, and a reference to a plurality of components may include a single embodiment. As used herein, the term "solvent" may refer to a single solvent or a mixture of solvents and can be used interchangeably with the term "composition".

In general, the present disclosure provides compositions for reducing or eliminating CO ₂ emissions from process vapors, such as, for example, coal-fired power plants that burn solid fuels, and methods of using the compositions. The solvents and methods disclosed herein recover / isolate CO ₂ from flue gas. Smoke can be produced by gas and oil-fired boilers, combined cycle power plants, coal gasification, and hydrogen and biogas plants.

In one embodiment, the solvent is an amino hindered alcohol having a vapor pressure of less than 0.1 kPa at 25 ° C, a polyamine having three or more amino groups having a vapor pressure of less than 0.009 kPa at 25 ° C, and a solvent of 8. Includes a carbonate buffer for buffering to a higher pH (eg, pH of about 8, about 10 or about 13). The solvent can have a vapor pressure of less than 1.85 kPa at 25 ° C.

In another embodiment, a polyamine having a vapor pressure of less than 0.009 kPa at 25 ° C. (eg, as 2-piperazine-1-ethylamine or diethylenetriamine) produces resilience to aerosol phase release due to very low pressure. However, this may be the result of a carbamate reaction with CO ₂ . Amino hindered alcohols at 25 ° C. with a vapor pressure of less than 0.1 kPa form an aerosol phase release by carbonate / bicarbonate reaction with CO ₂ . In a specific embodiment, a hindered alcohol containing a low vapor pressure (0.009) polyamine results in aerosol formation below 32 mg / Nm ³ . In a specific embodiment, a hindered alcohol containing a low vapor pressure (0.009) polyamine results in aerosol formation of less than 28 mg / Nm ³ . In other embodiments, hindered alcohols containing low vapor pressure (0.009) polyamines have more than half of the aerosol below 32 mg / Nm ³ . In another embodiment, hindered alcohols containing low vapor pressure (0.009) polyamines have more than half of the aerosol below 28 mg / Nm ³ .

In one example, the solvent may include an aqueous solution of 2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and potassium carbonate. Solvents and methods have preferred solvent regeneration (ie, low input energy content), chemical stability, vapor pressure, total heat consumption, net circulation capacity, and reaction kinetics. Solvents and methods also result in low aerosol and nitrosamine emissions and virtually no foaming.

In one example, the solvent is an aminohinderd alcohol having a vapor pressure of less than 0.1 kPa at 25 ° C, a polyamine having three or more amino groups having a vapor pressure of less than 0.009 kPa at 25 ° C, and a carbon dioxide buffer. ,including. The solvent has a vapor pressure of less than 1.85 kPa at 25 ° C. Polyamine is a combination of 2-piperazine-1-ethylamine and diethylenetriamine, and aminohindard alcohol is a combination of 2-methylamino-2-methyl-1-propanol and 2-amino-2-methylpropanol. It is a thing.

For illustration purposes, 2-amino-2-methylpropanol and 2-methylamino-2-methyl-1-propanol have steric hindrance with low heat absorption, high chemical stability, and relatively low reactivity. Alcohol. Piperazine-1-ethylamine and diethylenetriamine have very fast kinetics and are chemically stable under the conditions disclosed herein. Piperazine-1-ethylamine and diethylenetriamine are very low in volatility and alleviate the environmental problems of the disclosed solvents. Piperazine-1-ethylamine and diethylenetriamine can act as accelerators for 2-amino-2-methylpropanol and 2-methylamino-2-methyl-1-propanol, providing high absorption activity and fast reaction kinetics. ..

The CO ₂ solvent may contain a carbon dioxide buffer. The pH range of the carbonate buffer can be from about 8.0 to about 13. The presence of carbonate buffer can increase the pH of the solvent. A pH of about 8.0 to about 9.0 allows for increased CO ₂ recovery in the form of bicarbonate. The carbonate buffer can be regenerated by heating the solvent. For example, percarbonate can be utilized.

Carbonated buffer salts can also be used. The amount of carbonate buffer used is sufficient to raise the pH of saliva to about 7.8 or higher, about 8.5 or higher, or about 9 or higher (eg, about 9 to about 11), regardless of the starting pH. There must be. Therefore, the amount of carbonate buffer used in the solvent depends on the implementation conditions. In one example, the carbonate buffer can be sodium carbonate, potassium carbonate, calcium carbonate, ammonium carbonate, or magnesium carbonate.

Bicarbonate can also be used. Exemplary bicarbonates include, for example, sodium bicarbonate, potassium bicarbonate, calcium bicarbonate, ammonium bicarbonate, and magnesium bicarbonate.

A two-component buffer composition can be additionally utilized. Exemplary two-component buffer compositions include a combination of sodium carbonate and sodium bicarbonate. In one example, the solvent sodium bicarbonate can be sodium bicarbonate coated with a desiccant.

The amount of carbonate buffer and amine accelerator in the solvent may be limited by the solubility of both components in water, resulting in a solid solubility limit of the aqueous solution. For example, at 25 ° C., the solubility of the potassium carbonate buffer in a CO ₂ rich solution is 3.6 m. Due to the limited solid solubility, lower consequent concentrations can slow the reaction rate and reduce the solution volume. For example, the combination of piperazine-1-ethylamine, diethylenetriamine, and carbonate buffer increases the resulting solubility.

When accelerator-absorbing amines such as piperazine-1-ethylamine and diethylenetriamine reach CO ₂ , an equilibrium reaction occurs to form carbamate and dicarbamate, as well as some free and bound accelerator amines. The addition of a carbonate buffer that reacts with the free and bound accelerator amine completes the equilibrium reaction, thereby resulting in more CO ₂ absorption.

In one example, the solvent is 2-amino-2-methylpropo in an amount of about 10% to about 32% by weight, about 11% to about 28% by weight, preferably about 13% to about 25% by weight. Contains noll. If about 12% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 19.5% by weight of 2-amino-2-methylpropanol may be desirable. If about 4% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 13.3% by weight of 2-amino-2-methylpropanol may be desirable. If about 40% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 24.2% by weight of 2-amino-2-methylpropanol may be desirable.

In another example, the solvent is 2-piperazine-1-ethylamine in an amount of about 10% to about 35% by weight, about 12% to about 30% by weight, preferably about 14% to about 28% by weight. include. If about 12% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 22.4% by weight of 2-piperazine-1-ethylamine may be desirable. If about 4% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 27.6% by weight of 2-piperazine-1-ethylamine may be desirable. If about 40% by volume of CO ₂ is generated at the inlet of the biogas CO ₂ recovery system, about 15.15% by weight of 2-piperazine-1-ethylamine may be desirable.

In a further example, the solvent is in an amount of about 0.1% to about 4% by weight, about 0.1% by weight to about 3% by weight, preferably about 0.1% by weight to about 0.35% by weight. Contains an amount of diethylenetriamine. If about 12% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 0.2% by weight of diethylenetriamine may be desirable. If about 4% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 0.35% by weight of diethylenetriamine may be desirable. If about 40% by volume of CO ₂ is generated at the inlet of the biogas CO ₂ recovery system, about 0.1% by weight of diethylenetriamine may be desirable.

In yet another example, the solvent is in an amount of about 0.8% to about 5% by weight, about 1% by weight to about 2.8% by weight, preferably 1.2% by weight to about 1.8% by weight. Contains 2-methylamino-2-methyl-1-propanol in an amount of. If about 12% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 1.5% by weight of 2-methylamino-2-methyl-1-propanol may be desirable. If about 4% by volume of CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 1.2% by weight of 2-methylamino-2-methyl-1-propanol may be desirable. If about 40% by volume of CO ₂ is generated at the inlet of the biogas CO ₂ recovery system, about 1.8% by weight of 2-methylamino-2-methyl-1-propanol may be desirable.

In additional examples, the solvent is in an amount of about 0.1% to about 6% by weight, about 0.2% by weight to about 3% by weight, preferably about 0.5% to about 1.0% by weight. Contains an amount of buffer (eg, potassium carbonate). If about 12% by volume CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 0.5% by weight potassium carbonate may be desirable. If about 4% by volume CO ₂ is generated at the inlet of the flue gas CO ₂ recovery system, about 0.7% by weight potassium carbonate may be desirable. If about 40% by volume CO ₂ is generated at the inlet of the biogas CO ₂ recovery system, about 0.4% by weight potassium carbonate may be desirable.

Solvent properties play a major role in determining both equipment size and process energy requirements. In certain situations, the following factors can be considered when choosing a solvent:
Renewable energy: Since the exothermic reaction that occurs in the absorber is reversed by applying heat in the reboiler, a solvent with low or lower absorption heat is desirable.
-Circulation capacity (difference in CO ₂ concentration between the solvent leaving the absorber and the solvent leaving the reboiler): The higher the circulation capacity, the lower the load on the reboiler, the lower the power consumption of the pump, and the miniaturization of the equipment is possible. Therefore, a solvent having a high circulation capacity or a higher circulation capacity is desirable because the investment cost is reduced.
-Evaporation loss: The solvent has a large evaporation loss and requires a wash section at the top of the absorber. Therefore, a solvent with low evaporation loss is desirable, thereby eliminating the need for a water wash section.
-Solubility in water: Amine containing bulky non-polar moieties with limited solubility in water. Therefore, a solvent having a water-soluble amine is desirable.
-Chemical stability: A solvent that is less susceptible to oxidative deterioration is desirable. The challenge for MEA is its vulnerability to oxidative degradation when exposed to exhaust fumes.
-Corrosiveness: Solvents and their potential degradation products must be of limited corrosiveness.
Foaming: If uncontrolled, foaming can lead to gas purification and uneven distribution of liquid flow in the absorption tower, which can reduce its performance. Therefore, a solvent with minimal or no foaming is desirable.
• Toxicity and environmental impact: Solvents with minimal or no toxicity and environmental impact are desirable, and • Aerosol and nitrosamine emissions: Aerosol and nitrosamine formation due to the volatile nature of aerosols and nitrosamines. A solvent with minimal or no is desirable.
Certain exemplary solvents have properties with respect to the aforementioned criteria as compared to other currently accepted industry standards (eg, MEA). These properties are illustrated by the following detailed experiments using MEA as the reference solvent. The particular solvents disclosed herein have low energy requirements and good chemical stability. The solvent-based method disclosed herein takes advantage of the properties of the solvent, thus resulting in a method that consumes less energy while minimizing its impact on the environment. Other advantages of the disclosed solvents and methods will become apparent in the light of the description described herein.
Various containers, absorbers, or tower devices known in the art can be used in the contact process. For example, the size and shape can be changed. The container can be provided with one or more inlet ports and one or more outlet ports. For example, the contacting step can be performed on an absorption column. In the contacting step, the gas such as the first composition can pass through the liquid composition such as the second composition. The parameters can be adapted to achieve the desired percentage of carbon dioxide recovery, such as, for example, at least 70%, or at least 80%, or at least 90% carbon dioxide recovery. Regeneration can be performed when looping back to the reactor for further treatment of the solvent. In one embodiment, after the contacting step, the second composition having the dissolved carbon dioxide is subjected to one or more carbon dioxide removal steps and further contacted with the first composition containing carbon dioxide. Form a third composition. Other known processing steps can be performed. For example, filtration can be performed. Pumps, coolers, and heaters can be used, as is known in the art.
The contacting process can be part of a larger process flow that includes both other steps before and after the contacting process. For example, the membrane separation step can also be performed as part of a larger process. For example, a PBI membrane can be used. The contacting process can also be part of a larger process in which the components are removed. In some preferred embodiments, the contact step is part of the carbon recovery process. For example, IGCC plants and carbon recovery are described in the literature. As is known in the art, pre-combustion recovery processes and compression cycles can be performed. Continuous processing or batch processing can be performed. The contacting step results in at least partial dissolution of the carbon dioxide of the first composition in the second composition.

Examples and Experiments The following examples show the methods and embodiments according to the present invention.
screening

In certain examples, an exemplary solvent was tested using a mini-vapor-liquid equilibrium (“VLE”) setup. The mini-VLE setup was equipped with six devices in parallel. The six devices were able to operate at different temperatures. Combinations with different solvent components and concentrations were screened at 40 ° C and 120 ° C. These solvent components screened were 2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, potassium carbonate, piperazine, 2-methyl. It was piperazine, N-ethylethanolamine, and N-methyldiethanolamine.

VLE measurement using autoclave

VLE measurements demonstrate the relationship between the partial pressure of CO ₂ in the gas phase and the loading (ie, concentration) of CO ₂ in the solvent at various temperatures. An autoclave device used to perform a VLE test will be described. The autoclave comprises a glass container, a stirrer, a pH sensor, and a pressure sensor. The capacity of the container was 1 liter. Before starting the experiment, a vacuum pump was used to reduce the pressure to -970 mbar. 0.5 liter of solvent was added to the container and heated so that equilibrium could be determined with a solvent at a constant temperature. VLE was measured at several CO ₂ partial pressures and temperatures.

At the beginning of the experiment, a CO ₂ pulse was applied. Subsequent pulses were performed only when the following two conditions were met. (1) The time between the two pulses was at least 45 minutes; and (2) the mean pressure value of the 5 minute data exceeds 1 mbar from the mean of the other 5 minute data points 15 minutes ago. Did not deviate. The latter condition ensured that subsequent pulses were given only when the pressure was stable. The pressure measured in the vessel at t = 0 seconds was subtracted from the pressure measured after the CO ₂ pulse. At higher temperatures, the vapor pressure of the solvent (measured in another experiment) was subtracted from the measured pressure.

4 and 6 show the results of the VLE test described above. The partial pressure of CO ₂ in the gas phase increased with temperature for a particular CO ₂ loading in the solvent. The point of interest of the solvent-based CO ₂ recovery process is the CO ₂ loading observed under "rich" and "lean" solvent conditions. The "lean" solvent is a fresh solvent that enters the absorber and is ideally CO ₂ free. A "rich" solvent is a solvent that exits the absorber with as much CO ₂ as possible absorbed. The two main parameters of the solvent that affect the absorption performance are (a) net circulation capacity (ie, difference in rich and lean loading); and (b) kinetics due to temperature changes in both lean solvent and flue gas. Is.

As shown in FIG. 3, the APBS solvent was used at 40 ° C. and 120 ° C. to determine the vapor-liquid equilibrium data of the APBS solvent (ie, CO ₂ loading (mol / L) vs. CO ₂ partial pressure (kPa)). Tested at ° C. APBS solvent to ₂ % by volume CO at the inlet of coal (12% by volume CO ₂ ) / gas (4% by volume CO ₂ ) combustion flue gas and biogas (40% by volume CO ₂ ) resulting from flue gas. Screening and optimization based on. The CO ₂ loading of the solvent increased as the partial pressure of CO ₂ increased. However, the temperature affected the magnitude of CO ₂ loading with respect to the CO ₂ partial pressure.

FIG. 5 shows the vapor-liquid equilibrium data of the solvent (APBS 12% by volume CO ₂ ) and MEA disclosed herein at different temperatures (ie, 40 ° C and 120 ° C) under absorption device and stripper conditions. Show a comparison. The point of interest of the solvent-based CO ₂ recovery process is the CO ₂ loading observed under "rich" and "lean" solvent conditions. The "lean" solvent is a fresh solvent that enters the absorber and is ideally CO ₂ free. A "rich" solvent is a solvent that exits the absorber with as much CO ₂ as possible absorbed. In the case of a typical coal-fired power plant (12% by volume CO ₂ ), the CO ₂ partial pressure of the exhaust gas flow is about 12 kPa. For countercurrent-based absorption systems, the rich solvent is in contact with this flue gas at the inlet and is defined as rich loading. Generally, the temperature of the rich solvent is considered to be 40 ° C. This results in a rich loading of 3.3 mol / L in the case of 90% CO ₂ recovery. The CO ₂ partial pressure should not exceed 1 kPa and therefore the lean loading should not exceed the corresponding value. Based on VLE measurements, the lean loading of APBS solvent at a CO ₂ partial pressure of 1 kPa is 0.74 mol / L. This data is very important commercially because the difference between rich loading and lean loading is the amount of CO ₂ recovered. In the case of APBS solvent, this difference is twice that of the benchmark solvent MEA currently used, reducing the solvent circulation rate by 50%. Low solvent circulation rates result in reduced solvent circulation cycles, reduced overall energy, degradation, and corrosion.

Dynamic measurement of CO ₂ reaction in aqueous solvent

With reference to FIG. 7, an apparatus used to determine the kinetics of CO ₂ that reacts with aqueous APBS will be described. The device comprises a glass stirring cell reactor with a planar and horizontal gas-liquid interface used to obtain measurements of absorptivity. The gas and liquid are agitated separately by the impeller. The setup was supplied by two reservoirs (equipped with heat exchangers), one for the gas phase and one for the liquid phase.

ＭＥＡ及びＡＰＢＳ／溶媒のエネルギー及びリボイラー負荷の比較 The absorption rates as a function of the partial pressure of CO ₂ at various temperatures using the device of FIG. 7 are shown in Table 1 below.

Comparison of MEA and APBS / solvent energy and reboiler loading

In order for CO ₂ to move from the liquid phase to the gas phase, a driving force based on partial pressure is required. Vapors provide this driving force, facilitating mass transfer of CO ₂ from the liquid phase to the gas phase. Energy is also involved in this, contributing to the overall load of the reboiler. CO ₂ from the liquid phase to the gas phase by finding the amount of water associated with the pure CO ₂ vapor produced (this energy is the form of lost water that needs to be provided by the reboiler). It is possible to determine the amount of energy associated with the mass transfer of. The total amount of energy / heat required to move CO ₂ from the liquid phase to the gas phase is expressed by Equation 8.

The solvent loaded with CO ₂ in the absorber can be heated to stripper temperature to regenerate CO ₂ . The solvent flow can be preheated with a lean-rich cross heat exchanger and then additional heat can be used to maintain the temperature of the solvent in the stripper (represented by formula 9).

Factors contributing to sensible heat are solvent flow, specific heat capacity of solvent, and temperature rise. Therefore, the parameter that can be changed is one solvent flow, which further depends on the concentration of one solvent and the loading of that one solvent. This can be reduced by circulating less solvent and maintaining the same CO ₂ production rate. This is confirmed by comparing the net volume of solvent defined as the difference in loading under absorption and desorption conditions.

ΔＨ^vap _H20は水の気化熱であり、Ｐ^* _CO2は吸収器の底にあるリッチ溶液と平衡状態にあるＣＯ_２の分圧である。 It is necessary to regenerate CO ₂ that is reversibly bound to the solvent. Desorption heat (Q _des ) corresponds to absorption heat. The stripping heat is expressed by the formula 10.

ΔH ^vap _H20 is the heat of vaporization of water and P ^* _CO2 is the partial pressure of _CO2 in equilibrium with the rich solution at the bottom of the absorber.

パイロットプラント試験－Ｅ．ＯＮ ＣＯ_２回収パイロット－オランダ国（６トン／日ＣＯ_２回収 Table 2 below shows a comparison of reboiler loads in a typical CO ₂ recovery plant based on 5M MEA and APBS 12% by volume CO ₂ solvent. The total calorific value in terms of reboiler loading is 2.3 GJ / ton CO ₂ in the case of APBS solvent, which is about 30.5% higher than that of MEA (ie 3.31 GJ / ton CO ₂ ). low.

Pilot plant test-E. ON CO ₂ recovery pilot-Netherlands (6 tons / day CO ₂ recovery

ＡＰＢＳ溶媒による劣化及び腐食 APBS 12 Volume% Solvent Test Campaign in Maasvlakte, The Netherlands. It was carried out at the ON CO ₂ recovery plant. The CO ₂ recovery plant is E.I. Receives flue gas from unit 2 of an ON coal-based power plant. The recovery plant can recover 1210 Nm ³ / hour of flue gas. A schematic diagram of the recovery plant is shown in FIG. Table 3 below is a legend of the schematic diagram of FIG. 3, and Table 4 shows E.I. The main parameters of the columns of the ON CO ₂ recovery plant are shown.

Deterioration and corrosion due to APBS solvent

Degradation of the solvent is often caused either thermally or by oxidation of the flue gas. The oxygen content of flue gas from a typical coal-fired power plant is from about 6% to about 7% by volume. Deterioration due to thermal solvent usually occurs in a hot zone such as a stripper. However, the degree of thermal deterioration is lower than that of oxidative deterioration. Degradation of the solvent leads to a decrease in the concentration of the active ingredient, corrosion of the device by the formed degradation products, and release of ammonia.

Degradation is visually observable as shown in FIG. 9, which includes photographs of MEA and APBS solvents during the campaign period lasting 1000 run hours. The color of the degraded MEA solution is almost black, but the color of the degraded APBS does not appear to change much from the start to the end of the test campaign. This indicates that APBS is more resistant to degradation than MEA. In addition, the APBS solvent has zero foaming tendency and shows high resistance to SO ₂ during flue gas.

As mentioned above, deterioration of the solvent leads to corrosion of the equipment of the CO ₂ recovery system. Most of the equipment that comes into contact with solvents is usually stainless steel. Therefore, the degree of corrosion inside the plant can be estimated based on the amount of metals such as Fe, Cr, Ni, and Mn dissolved in the solvent. FIG. 4 shows the metal content of APBS and MEA during the pilot plant campaign. The metal content of APBS remained less than 1 mg / L after 1000 run hours. By comparison, during the previous MEA campaign at the same pilot plant, the metal content of MEA was about 80 mg / L within 600 operating hours. This comparison of APBS and MEA is serious because the metal content of the solvent correlates with the amount of corrosion of the equipment caused by the solvent, as APBS is known to be rapidly degraded by those skilled in the art. It shows that it does not cause corrosion of equipment rather than (leading to corrosion).

Ammonia (NH ₃ ) is a degraded product of the CO ₂ recovery solvent. Since ammonia is volatile, only a small amount of CO ₂ -free flue gas may be released into the atmosphere. Therefore, monitoring and minimizing ammonia emission levels is essential. FIG. 5 shows E. Ammonia release levels of MEA and APBS measured during pilot / campaign at the ON CO ₂ recovery plant are shown. In most campaigns, the ammonia emission level of APBS solvent was less than 10 mg / Nm ³ . This is in stark contrast to the ammonia release levels of MEA solvents in the range of about 10 mg / Nm ³ to about 80 mg / Nm ³ . Therefore, APBS is a safer solvent than MEA in terms of the production and release of ammonia due to degradation.

Aerosol of APBS solvent using impactor and impinger

The aerosol box was installed at the sampling point above the wash section of the pilot plant. From the preliminary test, it was decided that the temperature inside the aerosol box should be 1.5 ° C higher than the temperature monitored at the storing tower and the measurement site. Due to the adjustment of the Anderson Cascade Impactor, the internal temperature of the aerosol box is very high, so it takes time for the pilot plant to stabilize. The initial measurement time was 63 minutes. The second measurement was about the same time (66 minutes). At the end of 66 minutes, we continued sampling the impinger. In the first measurement, the temperature at the sample position changed from 39.94 ° C to 41.05 ° C, while the temperature inside the aerosol measurement box changed from 40.8 ° C to 42.2 ° C. In the second measurement, the temperature at the sample position varies from 39.7 ° C to 41.4 ° C, and the aerosol box temperature varies from 40.7 ° C to 42.2 ° C. Samples from the aerosol were captured from the impactor stage 28.3 L / min flow and collected by adding 5 mL of water to a vial with each filter paper. After shaking the vial, add 8 volumes for further analysis by LC-MS.

Table 10 shows the results of polyamines, which are solvent components, and amino hindered alcohols derived from impactor (aerosol) droplets and impinger (vapor). According to the results of Example 1, most amines are detected in the impactor. The absolute amount of 2-piperazine-1-ethylamine is as expected. Furthermore, the ratio of 2-amino-2-methylpropanol to 2-piperazine-1-ethylamine is as expected. The results of Example 2 show that many amines are present in the impinger, not the impactor. This was due to the inclusion of both aerosol and vapor-based emissions at the second hour of sampling. Therefore, most of the contribution to impinger is due to the aerosol component.

The concentration of amine in the droplets collected by the impactor is about 3% by weight. Therefore, most of the contents of the droplets are water. It has a very low concentration in the droplets compared to more than 50% by weight MEA aerosols from experiments performed in pilot plants using similar methods.

The aerosol box classifies the particles into one of eight stages, with a particle distribution of 0.43 mm to 11 mm. Stage 1 contains the largest particles and step 8 contains the smallest particles. In the first measurement, most aerosol particles were collected in the upper three stages, with a maximum value of around 5.8 mm to 9 mm. In the second measurement, most of the aerosol particles were collected in the top four stages, with a maximum value of around 4.7 mm to 5.8 mm. The total weight collected from all stages was 421 mg and 690 mg in the first and second experiments, respectively. The corresponding aerosol concentrations were 271 mg / Nm ³ and 423 mg / Nm ³ in the first and second measurements, respectively. The particle size distribution of the aerosol over eight steps of both measurements is shown in FIG. Overall, this indicates that APBS is more resilient to aerosol formation / formation than MEA.

Nitrosamine release of APBS solvent using impactors and impinger

パイロット試験－米国エネルギー省の国立炭素回収センター（ＮＣＣＣ）－４体積％ＣＯ_２排煙 Nitrosamines are known to be carcinogenic. However, nitrosamines are also present in the environment. Therefore, it is important to quantify the degree of nitrosamines that accumulate in the solvent and are released into the atmosphere. Primarily, secondary amines react with NO ₃ ^- accumulated in the solvent from flue gas to form nitrosamines. However, listing all specific nitrosamines can be a daunting task. Therefore, only total nitrosamines in the form of functional group "NNO" are listed. Table 8, the nitrosamine content of the first collision was below the measured threshold, i.e. less than 15 μg / kg, and the content of the second collision was 15 μg / kg. A total of 15 μg / kg * 0.1 kg + 15 μg / kg * 0.1 kg is less than 3 μg of nitrosamines in a period of 66 minutes + 60 minutes of the experiment. The nitrosamine concentration obtained in the gas phase at the sample position is less than 4.4 μg / Nm ³ .

Pilot Test-US Department of Energy National Carbon Recovery Center (NCCC) -4 Volume% CO ₂ Smoke Emissions

A test campaign for 4% by volume APBS solvent was conducted at the US Department of Energy's NCCC CO ₂ capture pilot plant in Southern Company, Alabama. The APBS solvent was specially developed to recover 3% to 6% by volume of CO ₂ from flue gas-based power generation.

APBS test: 4% by volume CO ₂ NCCC CO ₂ recovery pilot plant

Ｌ／Ｇ比の効果 APBS tests were conducted from March 2014 to April 2014 and February 2015 to March 2015 for detailed parametric tests and baselines using state-of-the-art MEA solvents. Table 7 below details a summary of test data collected from the NCCC pilot test. All tests included the following conditions:
(1) APBS solvent;
(2) Washing water flow = 10000 lb / hour;
(3) Outlet gas temperature of wash water section = 110F;
(4) Three-stage filling (J19 was filled by two beds);
(5) No intermediate cooling; and (6) steam of 35 psi and 268 F (enthalpy = 927 Btu / lb).

Effect of L / G ratio

ストリッパー圧力の影響 The stripper pressure was kept constant at 10 psig between runs J3 and run J5. Renewable energy passes through the minimum value at L / G = 0.75 weight / weight (or 6000 lb / hour liquid flow in the case of 8000 lb / hour gas flow). The minimum values of the "smooth curve" were an L / G ratio of about 0.76 (weight / weight) and about 1416 Btu / lb. Table 8 below shows the details of the data plotted in FIG.

Effect of stripper pressure

最適なＬ／Ｇ比及びストリッパー圧力 The effect of stripper pressure on regeneration efficiency is shown in FIG. The L / G ratio was kept constant at 0.75 weight / weight. Renewable energy passes through a sharp minimum with a stripper pressure close to 15 psig. The minimum value of the "smooth curve" is that of a stripper pressure of about 14 psig and 1325 Btu / lb CO ₂ . Table 9 below shows the details of the data plotted in FIG.

Optimal L / G ratio and stripper pressure

The CO ₂ absorption efficiency of Execution J15 (shown in Table 8) was 92.5%, and the renewable energy was the minimum. This indicates that the renewable energy under the conditions of execution J15 is about 1290 Btu / lb CO ₂ (or 3.0 GJ / ton CO ₂ ) when the CO ₂ removal efficiency is 90%. From the plots of FIGS. 7 and 8, 90% CO ₂ recovery is achieved with NCCC at G = 8000 lb / hour, L / G ratio 0.76 (ie L = 6080 lb / hour), and stripper pressure of 14.5 psig. It is necessary to obtain an overall minimum value of less than 1250 Btu / lb (2.9 GJ / ton CO ₂ ).

Effect of intermediate cooling

Execution J16 and Execution J17 were performed under the same conditions, except that Execution J17 was performed with intermediate cooling. When intermediate cooling is used, the renewable energy is slightly reduced (less than 0.3%) to 1434.4 Btu / lb CO ₂ , which means that intermediate cooling is effective in reducing the renewable energy of 4% by volume CO ₂ flue gas. It was suggested that it may not be the target.

Effect of number of filling beds

Execution J16 and J19 were performed under the same conditions, except that execution J19 was performed in two beds. Using two beds, the renewable energy increased to 1515.1 Btu / lb CO ₂ , but the CO ₂ removal efficiency was slightly higher at 90.4% (compared to 89.5% for run J16). This is because the APBS solvent of the present disclosure is about 5% more renewable energy than what is required in three beds, in two filled beds (6 meters or 20 feet in PTSU). It shows that 90% of CO ₂ could be removed.

Expected minimum energy consumption

The predicted renewable energy of 90% CO ₂ recovery (1290 Btu / lb CO ₂ or 3.0 GJ / ton CO ₂ ) using the solvents of the present disclosure is 35% from the value reported in the MEA of gas-fired boiler flue gas. ~ 40% lower. However, this is not the lowest achievable value with APBS solvent. While the PSTU is designed to operate with a 30% MEA that is flexible enough to accommodate other solvents, the NCCC lean / rich heat exchanger has the viscosity of the APBS solvent compared to the 30% MEA. Is not designed to be expensive. Therefore, the approach temperature measured during the APBS solvent test was higher than the MEA approach temperature and did not reach the optimum heat recovery rate.

In simulations using g-PROMs, 1200 Btu / lb CO ₂ (2.8 GJ) to achieve 90% CO ₂ removal under the following conditions with optimal lean / rich heat exchanger and advanced stripper design: A minimum renewable energy of / ton CO ₂ ) can be achieved.
(1) Smoke exhaust of 4.3% by volume CO ₂ and 16% by volume O ₂ (G = 8000 lb / hour in PSTU);
(2) Absorbed gas velocity = 9 ft / sec (PSTU absorber diameter = 2 feet, area = 3.142 ft ² );
(3) L / G ratio 0.76 weight / weight (or L = 6080 lb / hour in PSTU); and (4) stripper pressure = 14.5 psig.
Effect of oxygen: Ammonia emission (16% by volume O ₂ )

溶存金属濃度 Table 10 shows ammonia (NH) measured at the steam flow at the wash water outlet in PSTU at NCCC for smoke emissions of 4.3% by volume CO ₂ and 16% by volume O ₂ (simulating a natural gas-fired boiler). ₃ ) Indicates the amount of emissions. The average ammonia emission was 3.22 ppm for extrapolation. The NH ₃ emissions measured by PSTU using 11.4% by volume CO ₂ and 8% by volume O ₂ (derived from a coal-fired boiler) and MEA as the solvent were 53.7 ppm. rice field. This is approximately 17-fold higher than the average APBS solvent (3.22 ppm) measured at approximately _twice the amount of O2 in the flue gas.

Dissolved metal concentration

During the test, samples were taken from the new solvent at the beginning of the test run and from the used solvent at the end of the test run. Similar tests were conducted for the 2013 MEA implementation. A comparison of the APBS solvent and MEA test results is shown in Table 11.

As can be seen, the chromium level of MEA was more than 22 times higher than that of APBS solvent after 2 months of testing. This indicates that MEA is much more corrosive than APBS solvent.

The NCCC concludes that the main source of selenium may be flue gas. Inlet flue gas from the APBS solvent test was not sampled for selenium or other metals. However, because the coal used at the Gaston power plant was from the same source, the metal levels in the flue gas did not change significantly from the 2013 MEA test to the 2014 APBS test. Let's go. The level of selenium was 3 times higher in the MEA sample at the end of the implementation, and this level (1950 ppb weight) was almost twice the RCRA limit of 1000 mg / L (same as the ppb weight of a liquid with a density of 1.0). be.

CO ₂ purity

Analysis of the CO ₂ flow after the concentrator revealed that it always contained more than 97% by volume, about 2.5% by volume of water vapor and 210 ppm of _N2 .

APBS discharge test

ＡＰＢＳニトロソアミン試験 Analysis of amines and degradation products in the gas leaving the wash was performed. The results are summarized in Tables 12 and 13 below.

APBS Nitrosamine Test

試験－ＭＴバイオメタンバイオガスアップグラデーションＣＯ_２回収パイロットプラント－４０体積％ＣＯ_２バイオガス A detailed nitrosamine APBS solvent test was performed. In all three samples tested (CCS-WTO-7, CCS-WTO-8, and CCS-WTO-10), the values of N-nitrosodiethanolamine and a series of nitrosamines set the detection limit of the two methods used. It fell below. The results are summarized in Tables 14 and 15 below.

Test-MT Biomethane Biogas Upgradation CO ₂ Recovery Pilot Plant-40% by Volume CO ₂ Biogas

An APBS 40% by volume solvent test campaign was conducted at the MT Biomethane Biogas Upgradation CO ₂ Recovery Pilot Plant in Zeven, Germany. An APBS solvent was specially developed to recover 40% by volume CO ₂ from biogas. The MT biomethane facility has a biogas upgrading capacity of 200 Nm ³ / hour to 225 Nm ³ / hour. Agricultural waste is used to produce biogas using digestive equipment. The heat required for solvent regeneration was provided by hot water.
APBS test: 40% by volume CO ₂ capture pilot plant

APBS tests were conducted from July 2014 to June 2015 for detailed parametric tests and baseline with aMDEA solvent. After using APBS in the plant, very little CO ₂ was emitted from the top of the absorber. Since the methane-rich flow from the top of the absorber should contain 2% mol of CO ₂ , all optimization tests were performed to meet this requirement.

Net loading capacity

The APBS solvent has been observed to have a net loading capacity of CO ₂ 1.5 times higher than aMDEA. FIG. 15 shows the results of volume comparison of aMDEA and APBS. As can be easily seen, APBS has a larger volume of CO ₂ than aMDEA. As the volume of the solvent relative to CO ₂ increases, the circulation rate of the solvent decreases, so it is necessary to reduce the size of the device.

Recovery of methane from biogas

FIG. 9 shows methane recovery using APBS solvent. Since APBS is inert to methane, the recovery rate from biogas exceeds 99.9%.

Foaming

One of the main operational challenges faced by aMDEA was weekly foaming, which resulted in excessive plant downtime, loss of biogas processing and loss of profits. In contrast, the use of APBS did not cause foaming in the absorber.

energy

FIG. 17 shows the thermal and electrical energy performance of APBS. The average thermal energy of APBS is about 0.55 kWh / Nm ³ of raw biogas. The electrical energy was raw biogas 0.1kWh / Nm ³ .

Structural chemicals

Over a period of time, the performance of aMDEA begins to deteriorate due to vapor pressure and deterioration. Therefore, regular composition of chemicals is required to achieve the required performance using aMDEA. In the case of APBS, it has been observed that there is no need for structural chemicals. FIG. 18 shows a comparison of aMDEA and APBS structural chemistries required for ongoing operation.

MT Biomethane Biogas Upgradation CO ₂ Recovery Pilot Plant Test

With APBS, thermal and electrical energy can be saved by up to about 20% and about 40%, respectively. Since APBS did not generate any foaming, APBS can improve the productivity of biogas treatment. Due to the long solvent life and very slow corrosion rate, the use of APBS can reduce the investment in the overall plant life.

Claims (31)

It ’s a solvent,
Amino hindered alcohol with a vapor pressure of less than 0.1 kPa at 25 ° C.
Polyamines having three or more amino groups with a vapor pressure of less than 0.009 kPa at 25 ° C.
Contains carbonated buffer,
Here, the solvent is a solvent having a vapor pressure of less than 1.85 kPa at 25 ° C. The polyamine is a combination of 2-piperazine-1-ethylamine and diethylenetriamine, and the aminohindard alcohol is 2-methylamino-2-methyl-1-propanol and 2-amino-2-methylpropanol. The solvent according to claim 1, which is a combination. The solvent according to claim 2, wherein the carbonate buffer produces a pH selected from the group consisting of about 7.8 or more, about 8.5 or more, and about 9 or more. The solvent according to claim 2, wherein the carbonate buffer increases CO ₂ absorption by less than 6 weight. The solvent according to claim 2, wherein piperazine-1-ethylamine and diethylenetriamine increase the solubility of CO ₂ at 25 ° C. by more than 3.6 mol. The solvent according to claim 1, wherein the combination of polyamine, amino hindered alcohol and carbonic acid buffer does not substantially show effervescence. The solvent according to claim 1, wherein the potassium carbonate buffer increases the resistivity of the SO ₂ reaction with polyamines and aminohindard alcohols by more than 2% by weight. The solvent according to claim 2, wherein the carbonate is selected from the group consisting of sodium carbonate, potassium carbonate, calcium carbonate, ammonium carbonate, magnesium carbonate, and combinations thereof. The solvent according to claim 1, wherein the amino hindered alcohol is about 10% by weight to about 32% by weight, and the polyamine is about 13% by weight to about 25% by weight. The solvent according to claim 1, wherein the weight% of the polyamine is about 0.1% by weight to about 4% by weight. The solvent according to claim 2, wherein the content of 2-amino-2-methylpropanol in the CO ₂ solvent is about 10% by weight to about 32% by weight. The solvent according to claim 12, wherein the content of 2-amino-2-methylpropanol in the CO ₂ solvent is about 13% by weight to about 25% by weight. The solvent according to claim 2, wherein the weight% of 2-piperazine-1-ethylamine in the CO ₂ solvent is about 10% by weight to about 35% by weight. The solvent according to claim 13, wherein the weight% of 2-piperazine-1-ethylamine in the CO ₂ solvent is about 14% by weight to about 28% by weight. The solvent according to claim 1, wherein the amino hindered alcohol is about 10% by weight to about 32% by weight, and the polyamine is about 13% by weight to about 25% by weight. The solvent according to claim 2, wherein the weight% of diethylenetriamine in the CO ₂ solvent is about 0.1% by weight to about 4% by weight. The CO ₂ solvent according to claim 16, wherein the weight% of the diethylenetriamine in the CO ₂ solvent is about 0.2% by weight to about 0.35% by weight. The solvent according to claim 1, wherein the content of 2-methylamino-2-methyl-1-propanol in the CO ₂ solvent is about 0.8% by weight to about 5% by weight. The solvent according to claim 17, wherein the weight% of 2-methylamino-2-methyl-1-propanol in the CO ₂ solvent is about 1.2% by weight to about 1.8% by weight. The solvent according to claim 1, wherein the weight% of the buffer solution in the CO ₂ solvent is about 0.1% by weight to about 6% by weight. The solvent according to claim 19, wherein the weight% of the buffer solution in the CO ₂ solvent is about 0.5% by weight to about 1.0% by weight. The solvent according to claim 1, wherein the aqueous accelerator solution comprises 2-amino-2-methylpropanol, 2-piperazine-1-ethylamine, diethylenetriamine, and 2-methylamino-2-methyl-1-propanol. The solvent according to claim 1, wherein the polyamine is 2-piperazine-1-ethylamine which is aerosolized at less than 5.6 mg / Nm ³ . The solvent according to claim 1, wherein the amino hindered alcohol is 2-amino-2-methylpropanol that aerosolizes at less than 16.4 mg / Nm ³ . Contacting at least one first composition containing carbon dioxide with at least one second composition to at least partially dissolve the carbon dioxide of the first composition in the second composition. The method comprising, wherein the second composition comprises an aminohindard alcohol, a polyamine having three or more amino groups, and a carbon dioxide buffer. The polyamine is a combination of 2-piperazine-1-ethylamine and diethylenetriamine, and the aminohindard alcohol is 2-methylamino-2-methyl-1-propanol and 2-amino-2-methylpropanol. 25. The solvent according to claim 25, which is a combination. 25. The solvent according to claim 25, wherein the polyamine is 2-piperazine-1-ethylamine which is aerosolized at less than 5.6 mg / Nm ³ . 25. The solvent according to claim 25, wherein the aminohinderd alcohol is 2-amino-2-methylpropanol that aerosolizes at less than 16.4 mg / Nm ³ . 25. The solvent according to claim 25, wherein the polyamine and the solvent having a vapor pressure of less than 0.009 kPa at 25 ° C. form an aerosol of less than 5.6 mg / Nm ³ . 25. The solvent according to claim 25, wherein the aminohindered alcohol having a vapor pressure of less than 0.1 kPa at 25 ° C. and the solvent form an aerosol of less than 16.4 mg / Nm ³ . 25. The solvent according to claim 25, wherein the concentration of the amino hindered alcohol and the polyamine of the amine in the aerosol droplet is less than 3% by weight.

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