Patent Application
20170274317
This application relates generally to and more particularly to carbon capture.
Separating CO2 from gas streams has been commercialized for decades in food production, natural gas sweetening, and other processes. Aqueous monoethanolamine (MEA) based solvent capture is currently considered to be the best commercially available technology to separate CO2 from exhaust gases, and is the benchmark against which future developments in this area will be evaluated. Unfortunately, amine-based systems were not designed for processing the large volumes of flue gas produced by a pulverized coal power plant. Scaling the amine-based CO2 capture system to the size required for such plants is estimated to result in an 83% increase in the overall cost of electricity from such a plant.
Accordingly, there is always a need for an improved solvent.
Embodiments described herein include, for example, compounds and compositions, and methods of making and methods of using the compounds and compositions. Systems and devices can also be provided which use these compounds and compositions and relate to the methods. For illustration, this disclosure relates to a carbon capturing solvent (an example termed “APBS”) and a methods for treating industrial effluent gases using the solvent. The solvent disclosed herein removes CO2 at a more efficient rate than MEA and degrades at a rate lower than other solvents (e.g., MEA).
In one embodiment, the composition and method disclosed herein may be implemented at various types of industrial plants, including power plants, for example. In one example, the solvent may include an aqueous mixture of 2-amino-2-methylproponol, 2-piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and potassium carbonate buffer salt. The composition may also contain less than about 75% by weight of dissolving medium (i.e., water) and may have a single liquid phase. In another example, the solvent may include an aqueous mixture of amino hindered alcohol, polyamine with three or more amino group and a carbonate buffer salt.
Additional features of the present disclosure will become apparent to those skilled in the art upon consideration of the following detailed description exemplifying the best mode for carrying out the disclosure.
Embodiments of devices, systems, and methods are illustrated in the figures of the accompanying drawings which are meant to be exemplary and not limiting, in which like references are intended to refer to like or corresponding parts, and in which:
As used herein, the term “solvent” can refer to a single solvent or a mixture of solvents and may be used interchangeable with the term “composition.”
The detailed description of aspects of the present disclosure set forth herein makes reference to the accompanying drawings and pictures, which show various embodiments by way of illustration. While these various embodiments are described in sufficient detail to enable those skilled in the art to practice the disclosure, it should be understood that other embodiments may be realized and that logical and mechanical changes may be made without departing from the spirit and scope of the disclosure. Thus, the detailed description herein is presented for purposes of illustration only and not of limitation. For example, the steps recited in any of the method or process descriptions may be executed in any order and are not limited to the order presented. Moreover, references to a singular embodiment may include plural embodiments, and references to more than one component may include a singular embodiment.
Generally, this disclosure provides a composition and method of using the composition to reduce or eliminate CO2 emissions from a process steam, e.g., as coal-fired power plants, which burn solid fuels. The solvent and method disclosed herein capture/sequester CO2 from flue gases. The flue gases may be generated by gas and oil fired boilers, combined cycle power plants, coal gasification, and hydrogen and biogas plants.
In one embodiment, a solvent an amino hindered alcohol with vapor pressure less 0.1 kPa at 25 C and a polyamine with three or more amino groups with vapor pressure less 0.009 kPa at 25 C, and a carbonate buffer to buffer the solvent to a pH greater than 8 (e.g., a pH of about 8, about 10, or about 13). The solvent can have a vapor pressure less than 1.85 kPa at 25 C.
In another embodiment, a polyamine with vapor pressure less than 0.009 kPa at 25 C (e.g., as 2-Piperazine-1-ethylamine or diethylenetriamine) creates resiliency to an aerosol phase emissions due to very low pressure, which may result of carbamate reaction with CO2. The amino hindered alcohol with vapor pressure less 0.1 kPa at 25 C will form aerosol phase emissions due to carbonate/bicarbonate reaction with CO2. In specific embodiment, a hindered alcohol with a polyamine with low vapor pressure (0.009) yields less than 32 mg/Nm3 aerosol formation. In specific embodiment, a hindered alcohol with a polyamine with low vapor pressure (0.009) yields less than 28 mg/Nm3 aerosol formation. In other embodiments, a hindered alcohol with a polyamine with low vapor pressure (0.009) yields more than half of aerosols being less than 32 mg/Nm3. In another embodiment, a hindered alcohol with a polyamine with low vapor pressure (0.009) yields more than half of the aerosols being less than 28 mg/Nm3.
In one example, the solvent may include an aqueous solution of 2-amino-2-methylproponol, 2-Piperazine-1-ethylamine, diethylenetriamine, 2-methylamino-2-methyl-1-propanol, and potassium carbonate. The solvent and method have favorable solvent regeneration (i.e., amount of input energy is low), chemical stability, vapor pressure, total heat consumption, net cyclic capacity, and reaction kinetics. The solvent and method also result in low emission of aerosols and nitrosamines, and substantially no foaming.
In one example, the solvent comprises an amino hindered alcohol having a vapor pressure less than 0.1 kPa at 25 C, a polyamine with three or more amino groups having vapor pressure less 0.009 kPa at 25 C, and a carbonate buffer. The solvent has a vapor pressure less than 1.85 kPa at 25 C. The polyamine can be 2-Piperazine-1-ethylamine and diethylenetriamine together, and the amino hindered alcohol can be 2-Methylamino-2-methyl-1-propanol and 2-amino-2-methylproponol together.
For illustration, 2-amino-2-methylproponol and 2-Methylamino-2-methyl-1-propanol are sterically hindered alcohols that have low absorption heats, high chemical stabilities, and relatively low reactivity. Piperazine-1-ethylamine and diethylenetriamine have very high, fast kinetics and are chemically stable under the conditions disclosed herein. Piperazine-1-ethylamine and diethylenetriamine have very low volatilities, which reduce environmental concerns of the disclosed solvent. Piperazine-1-ethylamine and diethylenetriamine may act as promoters for 2-amino-2-methylproponol and 2-methylamino-2-methyl-1-propanol to provide high absorption activity and fast reaction kinetics.
The CO2 solvent may contain a carbonate buffer. A pH range for the carbonate buffer may be between about 8.0 and about 13. The presence of the carbonate buffer can increase the pH of the solvent. A pH of about 8.0 to about 9.0 allows for increased CO2 capture in the form of bicarbonate salts. The carbonate buffer may be regenerated when the solvent is heated. For example, percarbonate may be utilized.
Carbonate buffer salts may also be used. The amount of carbonate buffer salt used should be sufficient to raise salivary pH to about 7.8 or more, about 8.5 or more, or about 9 or more (e.g., about 9 to about 11), irrespective of the starting pH. Thus, the amount of carbonate buffer salt used in the solvent will depend upon implementation conditions. In an example, the carbonate buffer salt may be sodium carbonate, potassium carbonate, calcium carbonate, ammonium carbonate, or magnesium carbonate.
Bicarbonate salts may also be used. Exemplary bicarbonate salts include, for example, sodium bicarbonate, potassium bicarbonate, calcium bicarbonate, ammonium bicarbonate, and magnesium bicarbonate.
Binary buffer compositions may additionally be utilized. An exemplary binary buffer composition includes a combination of sodium carbonate and sodium bicarbonate. In an example, the sodium bicarbonate of the solvent may be dessicant-coated sodium bicarbonate.
An amount of carbonate buffer and amine promoter in the solvent may be limited by the solubility of both components in water, resulting in a solid solubility limit for aqueous solutions. For example, at 25 C, the solubility of potassium carbonate buffer in a CO2 rich solution is 3.6 m. With the solid solubility limitation, the resulting lower concentration can result in a slow reaction rate and low solution capacity. By combining Piperazine-1-ethylamine, Diethylenetriamine, and carbonate buffer, for example, the resultant solubility increases.
When promoter absorbent amines such as Piperazine-1-ethylamine and Diethylenetriamine reach with CO2, an equilibrium reaction occurs to form carbamate and dicarbamate and some free and bound promoter amines. Because of the addition of carbonate buffer salt, which reacts with free and bound promoter amines, the equilibrium reaction is driven to completion, thereby resulting in more CO2 absorption.
In an example, the solvent contains 2-amino-2-methylproponol in an amount of about 10 wt % to about 32 wt %, about 11 wt % to about 28 wt %, and preferably in an amount of about 13 wt % to about 25 wt %. When about 12 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 19.5 wt % of 2-amino-2-methylproponol may be desirable. When about 4 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 13.3 wt % of 2-amino-2-methylproponol may be desirable. When about 40 vol % CO2 is experienced at the inlet of a biogas CO2 capture system, about 24.2 wt % of 2-amino-2-methylproponol may be desirable.
In another example, the solvent contains 2-Piperazine-1-ethylamine in an amount of about 10 wt % to about 35 wt %, about 12 wt % to about 30 wt %, and preferably in an amount of about 14 wt % to about 28 wt %. When about 12 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 22.4 wt % of 2-Piperazine-1-ethylamine may be desirable. When about 4 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 27.6 wt % of 2-Piperazine-1-ethylamine may be desirable. When about 40 vol % CO2 is experienced at the inlet of a biogas CO2 capture system, about 15.15 wt % of 2-Piperazine-1-ethylamine may be desirable.
In a further example, the solvent contains diethylenetriamine in an amount of about 0.1 wt % to about 4 wt %, about 0.1 wt % to about 3 wt %, and preferably in an amount of about 0.1 wt % to about 0.35 wt %. When about 12 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 0.2 wt % of diethylenetriamine may be desirable. When about 4 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 0.35 wt % of Diethylenetriamine may be desirable. When about 40 vol % CO2 is experienced at the inlet of a biogas CO2 capture system, about 0.1 wt % of diethylenetriamine may be desirable.
In yet another example, the solvent contains 2-Methylamino-2-methyl-1-propanol in an amount of about 0.8 wt % to about 5 wt %, about 1 wt % to about 2.8 wt %, and preferably in an amount of about 1.2 wt % to about 1.8 wt %. When about 12 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 1.5 wt % of 2-Methylamino-2-methyl-1-propanol may be desirable. When about 4 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 1.2 wt % of 2-methylamino-2-methyl-1-propanol may be desirable. When about 40 vol % CO2 is experienced at the inlet of a biogas CO2 capture system, about 1.8 wt % of 2-methylamino-2-methyl-1-propanol may be desirable.
In an additional example, the solvent contains buffer (e.g., potassium carbonate) in an amount of about 0.1 wt % to about 6 wt %, about 0.2 wt % to about 3 wt %, and preferably in an amount of about 0.5 wt % to about 1.0 wt %. When about 12 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 0.5 wt % of potassium carbonate may be desirable. When about 4 vol % CO2 is experienced at the inlet of a flue gas CO2 capture system, about 0.7 wt % of potassium carbonate may be desirable. When about 40 vol % CO2 is experienced at the inlet of a biogas CO2 capture system, about 0.4 wt % of potassium carbonate may be desirable.
Characteristics of the solvent play a major role in determining both equipment size and process energy requirements. In certain circumstances, the following factors can be considered when choosing a solvent:
A variety of container, absorber, or tower devices as known in the art can be used for the contacting step. The size and shape, for example, can be varied. The container can have one or more input ports and one or more exit ports. For example, the contacting step can be carried out in an absorption column. In the contacting step, a gas such as the first composition can be passed through a liquid composition such as the second composition. One can adapt the parameters to achieve a desired percentage of carbon dioxide capture such as, for example, at least 70%, or at least 80%, or at least 90% carbon dioxide capture. Recycling can be carried out where solvent is looped back into a reactor for further processing. In one embodiment, after the contacting step, the second composition with its dissolved carbon dioxide is subjected to one or more carbon dioxide removal steps to form a third composition which is further contacted with a first composition comprising carbon dioxide. Other known processing steps can be carried out. For example, filtering can be carried out. As known in the art, pumps, coolers, and heaters can be used.
A contacting step can be part of a larger process flow with other steps both before and after the contacting step. For example, membrane separation steps can also be carried out as part of the larger process. For example, PBI membranes can be used. The contacting step can be also part of a larger process in which components are removed. In some preferred embodiments, the contacting step is part of a carbon capture process. For example, an IGCC plant and carbon capture are described in the literature. As known in the art, pre-combustion capture processes and compression cycles can be carried out. Continuous or batch processing can be carried out. The contacting step results in at least partial dissolution of the carbon dioxide of the first composition in the second composition.
The following examples illustrate methods and embodiments in accordance with the invention.
In certain examples, a mini-vapor-liquid equilibrium (“VLE”) setup was used to test exemplary solvents. The mini-VLE setup included six (6) apparatuses in parallel. The 6 apparatuses were capable of being operated at different temperatures. Different combinations of solvent components and concentrations were screened at 40 C and 120 C. These solvents components screened were 2-amino-2-methylproponol, 2-Piperazine-1-ethylamine, Diethylenetriamine, 2-Methylamino-2-methyl-1-propanol, potassium carbonate, piperazine, 2-methyl piperazine, N-ethyl ethanolamine, and N-methyl diethanolamine.
VLE measurements demonstrate the relationship between partial pressure of CO2 in the vapor phase and the loading (i.e., concentration) of CO2 in a solvent at different temperatures. An autoclave apparatus used to perform VLE testing is described. The autoclave includes a glass vessel, a stirrer, a pH sensor, and pressure sensors. The volume of the vessel was 1 liter. Prior to commencing the experiment, pressure was brought down to −970 mbar using a vacuum pump. 0.5 liter of solvent was added to the vessel and was heated up so equilibrium could be determined at a constant temperature of the solvent. VLE was determined at several CO2 partial pressures and temperatures.
At the start of the experiment, a CO2 pulse was performed. A subsequent pulse was performed only if the following two conditions were satisfied: (1) the time between two pulses was at least 45 minutes; and (2) the average pressure value of 5 minutes of data did not deviate by more than 1 mbar from the average value of 5 other minutes of data points 15 minutes earlier. The latter condition ensured the subsequent pulse was only given when the pressure was stabilized. The pressure measured in the vessel at t=0 s was subtracted from pressures measured after the CO2 pulses. At higher temperatures, the vapor pressure of the solvent (measured in a separate experiment) was subtracted from the measured pressures.
As indicated in
Referring to
The rate of absorption as a function of CO2 partial pressure at various temperatures using the device of
For the CO2 to be transferred from the liquid phase to the gas phase, there needs to be a driving force on the basis of partial pressure. Steam provides this driving force, resulting in the mass transfer of CO2 from the liquid phase to the gas phase being enhanced. This also has energy associated with it, which contributes to the overall reboiler duty. By finding out the amount of water associated with the pure CO2 steam produced (this energy being in the form of water lost that needs to be provided by the reboiler), the amount of energy associated with mass transfer of CO2 from the liquid phase to the gas phase can be determined. The total amount of energy/heat needed to transfer CO2 from the liquid phase to the gas phase is represented by Equation 8.
Q
T
=Q
sens
+Q
des
+Q
strip Equation 8
A solvent loaded with CO2 in the absorber may be heated up to stripper temperature for the regeneration of CO2. A solvent stream can be pre-heated in the lean-rich cross heat exchanger and then additional heat may be used to maintain the temperature of a solvent in the stripper (represented by Equation 9).
Contributing factors to sensible heat are solvent flow, specific heat capacity of a solvent, and the temperature increase. Thus, the parameter that can be varied is one solvent flow, which further depends on the concentration of one solvent and the one solvent's loadings. This can be decreased by circulating less solvent and maintaining the same CO2 production rate. This is checked by means of comparing the net capacity of a solvent, which is defined as the difference in the loading at absorption and desorption conditions.
The CO2 which is reversibly bound to a solvent needs to be regenerated. The heat of desorption (Qdes) is equivalent to the heat of absorption. The stripping heat is represented by Equation 10.
ΔHH2Ovap is the heat of vaporization of water and P*CO2 is the partial pressure of CO2 at equilibrium with the rich solution at the bottom of the absorber.
Table 2 below shows a comparison of the reboiler duty in a typical CO2 capture plant based on 5 M MEA and APBS 12 vol % CO2 solvent. The total heat requirement in terms of reboiler duty was 2.3 GJ/ton CO2 for the APBS solvent, which is about 30.5% lower than that of MEA (i.e., 3.31 GJ/ton CO2).
The APBS 12 vol % solvent test campaign was conducted at the E.ON CO2 capture plant in Maasvlakte, Netherlands. The CO2 capture plant receives flue gas from unit 2 of the E.ON coal based power station. The capture plant can capture 1210 Nm3/h of flue gas. A schematic representation of the capture plant is depicted in
Degradation of solvent often occurs either thermally or due to oxidation in the flue gas. The oxygen content of flue gas from a typical coal fired power plant is about 6% to about 7% by volume. Thermal solvent degradation typically occurs in hot zones such as in the stripper. However, the extent of thermal degradation is lower than oxidative degradation. Degradation of the solvent leads to loss in active component concentration, corrosion of the equipment by the degradation products formed, and ammonia emissions.
Degradation can be observed visually as shown in
As mentioned above, degradation of solvent leads to corrosion of the equipment of CO2 capture systems. Typically, most of the equipment in contact with the solvent is stainless steel. Thus, based on the amount of metals such as Fe, Cr, Ni, and Mn dissolved in the solvent, it is possible to estimate the extent of internal plant corrosion.
Ammonia (NH3) is a degradation product of CO2 capture solvents. Ammonia, since it is volatile, may only be emitted into the atmosphere in small quantities with CO2 free flue gas. Consequently, monitoring and minimization of ammonia emission levels is essential.
The aerosol box has been installed at a sampling point above the water wash section of the pilot plant. From prelimairy tests it has been decided to raise the temperature in the aerosol box 1.5 C above the temperature monitored in the sorption tower and at the measurement location, It takes some time for the conditions in the pilot plant to stabilize as the internal temperature of the aerosol box very fast in order to condition the Anderson cascade impactor. The duration of the first measurement was for 63 min. The second measurement was of at least equal duration (66 min). At the end of 66 min, the impinger sampling was continued. In the first measurement the temperature at the sample location varied between 39.94 and 41.05 C, while the temperature in the aerosol measurement box varies between 40.8 and 42.2 C. In the second measurement the temperature at the sample location varies between 39.7 and 41.4 C and the aerosol box temperature between 40.7 and 42.2 C. Samples from aerosol trapped from the 28.3 L/min flow through the impactor stages and collected by adding 5 mL of water to vials with each one of the filter papers. After shaking the vials, the 8 liquid volumes are added for further analysis by LC-MS.
Table 10 shows the results from the solvent components polyamine and the amino hindered alcohol from impactor (aerosol) droplets and impingers (vapour). As per the results of experiment 1, most of the amines are found from the impactor. The absolute amount of 2-Piperazine-1-ethylamine is as expected. Moreover the ratio of 2-amino-2-methylproponol and 2-Piperazine-1-ethylamine is as expected. The results from experiments 2 indicate that more amount of amines is present in the impingers rather than the impactor. This is due to the fact that the second hour of the sampling included both aerosols and vapour based emissions. Thus, most of the contribution in the impingers is due to the aerosol component.
The concentration of amines in the droplets collected by the impactor is about 3 wt. %. Thus, most of content of the droplets is water. This is quite low as compared to MEA aerosols, whose concentration in the droplets is greater than 50 wt. %. from experiments performed at the pilot plant using a similar method.
The aerosol box separates particles into one of eight stages with a particle distribution from 0.43 mm to 11 mm. Stage 1 contains the biggest particles, stage 8 contains the smallest. In the first measurement, most aerosol particles were collected on the top three stages with a maximum near 5.8 mm to 9 mm. In the second measurement, most aerosol particles were collected on the top four stages with a maximum near 4.7 mm to 5.8 mm. The total weight collected from all the stages was 421 mg and 690 mg for the first and second experiments, respectively. The corresponding aerosol concentration was 271 mg/Nm3 and 423 mg/Nm3 for first and second measurements, respectively. The aerosol particle size distribution over the eight stages for both measurements is given in
Nitrosamines are known to be carcinogenic. However, nitrosamines are also present in the environment. Thus, it is important to quantify the extent of nitrosamines accumulated in the solvent and emitted to the atmosphere. Primarily, secondary amines form nitrosamines on reaction with NO3− accumulated in the solvent from the flue gas. However, it is a very tedious task to list all the specific nitrosamines. Thus, only the total nitrosamines in the form of the functional group “NNO”. Table 8, the nitrosamine content of the first impinge was below the measured threshold, i.e <15 ug/kg, the content for the second impinge is 15 ug/kg. A total of <15 ug/kg*0.1 kg+15 ug/kg*0.1 kg is less than 3 ug total nitrosamines in the 66+60 min duration of the experiment. The resulting nitrosamine concentration in the vapor phase at the sample location is <4.4 ug/Nm3.
The APBS 4 vol % solvent test campaign was conducted at US-DOE's NCCC CO2 capture pilot plant at the Southern Company in Alabama. The APBS solvent was specifically developed to capture 3-6 vol % CO2 from flue gas emissions gas based power generations.
The APBS testing was conducted from March 2014 to April 2014 and February 2015 to March 2015 for detailed parametric testing and baseline using state of the art MEA solvent. Table 7 below details a summary of the test data collected from the NCCC pilot testing. All of the testing involved the following conditions:
(1) APBS solvent;
(2) Wash water flow=10,000 lb/hr;
(3) Wash water section exit gas temperature=110 F;
(4) Three stages of packing (J19 was packed with 2 beds);
(5) No inter-stage cooling; and
(6) Steam at 35 psi and 268 F (enthalpy=927 Btu/lb).
The stripper pressure was held constant at 10 psig for runs J3 to J5. The regeneration energy goes through a minima at L/G=0.75 w/w (or 6,000 lb/hr liquid flow for 8,000 lb/hr of gas flow). The “smooth curve” minima was at L/G ratio of about 0.76 (w/w) and about 1,416 Btu/lb. Table 8 below details the data plotted in
The effect of the stripper pressure on regeneration efficiency is shown in
The CO2 absorption efficiency for Run J15 (illustrated in Table 8) was 92.5%, which had the minimum energy of regeneration. This shows that the regeneration energy for the conditions of Run J15, but for CO2 removal efficiency of 90%, would have been about 1,290 Btu/lb CO2 (or 3.0 GJ/ton CO2). From the plots in
Runs J16 and J17 were performed under the same conditions, except run J17 was carried out with inter-cooling. The regeneration energy reduced only slightly (less than 0.3%) to 1,434.4 Btu/lb CO2 with the use of inter-cooling, suggesting that inter-cooling may not be effective in reducing the regeneration energy for 4 vol % CO2 flue gas.
Runs J16 and J19 were performed under the same conditions, except run J19 was carried out 2 beds. The regeneration energy increased to 1,515.1 Btu/lb CO2 with the use of 2 beds, but the CO2 removal efficiency was slightly higher at 90.4% (as against 89.5% for run J16). This shows that the APBS solvent of the present disclosure was capable of removing 90% CO2 with two packed beds (of 6 meter or 20′ packing in PTSU) with about 5% more regeneration energy as compared to that required with 3 beds.
The projected regeneration energy for 90% CO2 capture (1,290 Btu/lb CO2 or 3.0 GJ/ton CO2) using the solvent of the present disclosure is 35% to 40% lower than the values reported for MEA for gas-fired boiler flue gas. However, this is not the lowest achievable value for the APBS solvent. The PSTU was designed for operation using 30% MEA with the flexibility to accommodate other solvents, but the NCCC lean/rich heat exchanger was not designed for the higher viscosity of the APBS solvent relative to 30% MEA. Thus, the measured approach temperatures during the APBS solvent test were higher than those for MEA leading to less than optimal heat recovery.
Simulations with g-PROMs have predicted that with an optimal lean/rich heat exchanger and an advanced stripper design, the minimum regeneration energy of 1,200 Btu/lb CO2 (2.8 GJ/ton CO2) can be achieved for CO2 removal of 90% under the following conditions:
(1) Flue gas with 4.3 vol % CO2 and 16 vol % O2 (G=8,000 lb/hr at PSTU);
(2) Absorber gas velocity=9 ft/sec (PSTU absorber diameter=2′, Area=3.142 ft2);
(3) L/G ratio of 0.76 w/w (or L=6,080 lb/hr at PSTU); and
(4) Stripper pressure=14.5 psig.
Table 10 illustrates ammonia (NH3) emissions measured in the vapor stream at the wash water outlet in the PSTU at NCCC for a flue gas with 4.3 vol % CO2 and 16 vol % O2 (simulating a natural gas fired boiler). As can be extrapolated, the average ammonia emissions were 3.22 ppm. The NH3 emissions measured at the PSTU while treating a flue gas with 11.4 vol % CO2 and 8 vol % O2 (from coal-fired boiler) with MEA as the solvent were 53.7 ppm. This is almost 17 times higher than the average for APBS solvent (3.22 ppm), which was measured with almost twice the amount of O2 in the flue gas.
During tests, samples were taken for fresh solvent at the beginning of the test runs and from spent solvent at the end of the test runs. Similar tests were carried out for MEA runs in 2013. A comparison of the results of the APBS solvent and MEA tests is depicted in Table 11.
As can be seen, the level of chromium for MEA was more than 22 times that in the APBS solvent, after two months of testing. This indicates that MEA is much more corrosive than the APBS solvent.
NCCC has concluded that the major source of selenium may be the flue gas. The inlet flue gas with APBS solvent testing was not sampled for selenium or other metals. However, since the coal used at the Gaston power plant was from the same source, the metals level in the flue gas would not have changed significantly from MEA tests in 2013 to those for APBS in 2014. The level of selenium is three times higher in the MEA sample at the end of the runs, and this level (1,950 ppb wt) is almost twice of the RCRA limit of 1,000 mg/L (which is the same as ppb wt for a liquid with specific gravity of 1.0).
The CO2 stream after the condenser was analyzed and it was found to be consistently higher than 97 vol % in CO2 with about 2.5 vol % water vapor and 210 ppm N2.
An analysis of amines and degradation products in the gas leaving the water wash was conducted. The results are summarized in Tables 12 and 13 below.
Detailed Nitrosamine APBS solvent testing was performed. In all three samples tested (CCS-WTO-7, CCS-WTO-8 and CCS-WTO-10), the values of N-Nitroso-diethanolamine and a series of nitrosoamines were below detection limits of the two methods used. The results are summarized in Tables 14 and 15 below.
An APBS 40 vol % solvent test campaign was conducted at the MT Biomethane biogas up-gradation CO2 capture pilot plant in Zeven, Germany. The APBS solvent was specifically developed to capture 40 vol % CO2 from biogas. The MT Biomethane facility has a biogas up-gradation capacity of 200 to 225 Nm3/hr. Agricultural waste is used to produce biogas using a digester. The heat needed for regeneration of the solvent was provided by hot water.
The APBS testing was conducted from July 2014 to June 2015 for a detailed parametric test and baseline with an aMDEA solvent. After APBS was used by the plant, CO2 released through the absorber top was negligible. The methane rich stream leaving from the top of the absorber should contain 2% mol of CO2, hence all the optimization test was conducted to meet this requirement.
It has been observed that the APBS solvent has a net loading capacity for CO2 1.5 times higher than aMDEA.
One of the major operational problems encountered by aMDEA was foaming once a week, which lead to undue stoppage of plant operations and loss of processing of biogas, and hence revenue. In contrast, the use of APBS did not result in any foaming in the absorber.
Over a period of time, due to vapor pressure and degradation, performance of aMDEA starts to diminish. Thus, a regular make-up of chemicals are needed to achieve required performance using aMDEA. In the case of APBS, it has been observed that there is no need for make-up chemicals.
Use of APBS leads to savings in thermal and electrical energy up to about 20% and to about 40%, respectively. Since APBS did not lead to a single occurrence of foaming, APBS can increase productivity of biogas processing. Due to higher solvent life and very low corrosion rate, the overall investment over the plant life can be decreased by using APBS.
This application claims priority to U.S. Provisional Patent Application Ser. No. 62/040,911, which is incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/IB2015/001855 | 8/21/2015 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62040911 | Aug 2014 | US |
