The potential for increased atmospheric CO2 emissions and accelerated consumption of deep geologic CO2 storage resources resulting from the large-scale deployment of a CCS-enabled unconventional fossil fuels industry in the U.S.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO₂) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO₂ storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO₂ from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO₂ capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO₂ emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO₂, in addition to storing potentially 900–5000 MtCO₂ in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO₂ emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO₂ stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO₂ storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO₂ storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.     

CO2 capture for refineries,a practical approach

This paper evaluates the opportunities and associated costs for post-combustion capture at a world-scale complex refinery. It is concluded that it is technically feasible to apply post-combustion capture at such a refinery. The costs for capture and sequestration from a gasifier are calculated to be lowest at about 30 Euro per ton; this process currently already produces a concentrated CO₂ stream. Next, the CO₂ source most suited for capture appears to be a combined stack, but there are a number of other sources that may be targeted at comparable costs. In total these sources may form about 40% of the overall refinery emissions. Our evaluations show the costs of capture from such sources based on available amine technology will be in the range of 90–120 Euro per ton, which is about 3–4 times higher than the current carbon trading values. The capture of CO₂ from a large amount of smaller CO₂ sources will bring along even much higher costs. A high-level study of the CO₂ emissions profile of a number of Shell refineries shows that, typically, up to 50% of the emitted CO₂ may be captured at similar costs. About 10–20% of concentrated CO₂ associated with hydrogen manufacturing may be captured at lower costs. The remainder of emitted dilute CO₂ will bring along significantly higher costs. Based on this study, it is concluded for the justification of the implementation of post-combustion capture at refineries, either a significant increase in carbon trading values, mandatory regulations, or a major technological break-through is required.     

Constraints on the in situ density of CO2 within the Utsira formation from time-lapse seafloor gravity measurements

At Sleipner, CO₂ is being separated from natural gas and injected into an underground saline aquifer for environmental purposes. Uncertainty in the aquifer temperature leads to uncertainty in the in situ density of CO₂. In this study, gravity measurements were made over the injection site in 2002 and 2005 on top of 30 concrete benchmarks on the seafloor in order to constrain the in situ CO₂ density. The gravity measurements have a repeatability of 4.3 μGal for 2003 and 3.5 μGal for 2005. The resulting time-lapse uncertainty is 5.3 μGal. Unexpected benchmark motions due to local sediment scouring contribute to the uncertainty. Forward gravity models are calculated based on both 3D seismic data and reservoir simulation models. The time-lapse gravity observations best fit a high temperature forward model based on the time-lapse 3D seismics, suggesting that the average in situ CO₂ density is about to 530 kg/m³. Uncertainty in determining the average density is estimated to be ±65 kg/m³ (95% confidence), however, this does not include uncertainties in the modeling. Additional seismic surveys and future gravity measurements will put better constraints on the CO₂ density and continue to map out the CO₂ flow.     

Simultaneous CO2 injection and water production to optimise aquifer storage capacity

The estimates for geological CO₂ storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO₂ that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential.In static capacity estimates, where the maximum stored amount of CO₂ is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO₂ is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO₂. The EU directive on geological CO₂ storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO₂ that can be injected.One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO₂ injection wells. This paper discusses results from simulations of CO₂ injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO₂ shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO₂ over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer.Several design options for the injection operations are investigated: Injection of CO₂ without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.     

Large-scale impact of CO2 storage in deep saline aquifers: A sensitivity study on pressure response in stratified systems

Large volumes of CO₂ captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO₂ plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO₂ and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO₂ injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO₂-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO₂ plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO₂ storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10^?18 m²). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Geological storage of CO2 in saline aquifers—A review of the experience from existing storage operations

The experience from CO₂ injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO₂ geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO₂ plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO₂ had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO₂/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.     

Geoelectrical methods for monitoring geological CO2 storage: First results from cross-hole and surface–downhole measurements from the CO2SINK test site at Ketzin (Germany)

The feasibility of monitoring CO₂ migration in a saline aquifer at a depth of about 650 m with cross-hole and surface–downhole electrical resistivity tomography (ERT) is investigated at the CO₂SINK test site close to Ketzin (Germany). The permanent vertical electrical resistivity array (VERA) consists of 45 electrodes (15 in the injection well Ktzi201 and 15 in each of the two observation wells Ktzi200 and Ktzi202), successfully placed on the electrically insulated casings, in the depth range of about 590–740 m with a spacing of about 10 m. The three Ketzin wells are arranged as perpendicular triangle with distances of 50 and 100 m.First synthetic modelling studies indicate an increase of the electrical resistivity of about 200% caused by CO₂ injection, corresponding to a bulk CO₂ saturation of 50%, which is in good agreement with laboratory studies. Finite difference inversion of field data delivers three-dimensional resistivity distributions between the wells which are consistent with the reservoir modelling studies.To increase the limited observation area provided by the cross-hole measurements, additional surface–downhole measurements were deployed. A main CO₂ migration in SE–NW direction is deduced from surface to downhole resistivity experiments.The first cross-hole time-lapse results show that the resolution and the coverage of the electrode array in the Ketzin setting are sufficient to resolve the expected resistivity changes on the characteristic length scale of the electrode array. Significant resistivity changes could be measured, however, detailed information on the CO₂ plume could not be resolved yet by VERA under the existing geological circumstances.     

Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

Heat of absorption of CO2 in aqueous ammonia and ammonium carbonate/carbamate solutions

A reaction calorimeter was used to determine the enthalpies of absorption of CO₂ in aqueous ammonia and in aqueous solutions of ammonium carbonate at temperatures of 35–80 °C. The heat of absorption of CO₂ with 2.5 wt% aqueous ammonia solution was found to be about 70 kJ/mol CO₂, which is lower than that with MEA (around 85 kJ/mol) at 35 and 40 °C. The value decreases with increased loading, but not to as low a value as expected by the carbonate–bicarbonate reaction (26.88 kJ/mol). The enthalpy of absorption of CO₂ in aqueous ammonia at 60 and 80 °C decreases with loadings at first, then increases between 0.2 mol CO₂/mol NH₃ and 0.6 mol CO₂/mol NH₃, and then decreases again. The behavior of the heat of absorption of CO₂ in 10 wt% ammonium carbonate solution was found to be the same as that of aqueous ammonia at loadings above 0.6 mol CO₂/mol NH₃. The heat of absorption increases with increasing temperature. The heats of absorption are directly related to the extent of the various reactions with CO₂ and can be assessed from the species variation in the liquid phase.     

CO2 capture from power plants: Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO₂ emission is increasing, the cost of the CO₂ capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO₂ capture from 600 MW_e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO₂-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO₂ capture process based on absorption/desorption with MEA solutions was performed.Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO₂ avoided cost of € 33 tonne⁻¹ CO₂ was found for a lean solvent loading of 0.3 mol CO₂/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO₂ of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh⁻¹ increase in the cost of electricity, compared to € 31.4 MWh⁻¹ for the power plant without capture.     

Natural analogue of the rise and dissolution of liquid CO2 in the ocean

The behavior of natural carbon dioxide (CO₂) droplets (8–10 mm in diameter) were observed in a seafloor hydrothermal system at the Okinawa Trough. The natural CO₂ droplet contain 95–98% of CO₂, 2–3% of H₂S, and other gas species. The ascending CO₂ droplets were tracked by a remotely operated vehicle (ROV), and depth, temperature, salinity, pH and partial pressure of CO₂ (pCO₂) in seawater near the CO₂ droplets were measured during droplet ascent by a conductivity-temperature-depth sensor (CTD) and in situ pH/pCO₂ sensor. The visual images of the rising CO₂ droplets were recorded with a high definition television camera on the ROV. A mapping survey (400 m × 400 m; 4 horizontal layers) revealed a dominant distribution of low pH area over the natural CO₂ venting site. The size and rise rate of CO₂ droplets decreased during their ascent in the water column from depths of 1424 to 679 m (a tracking interval of 745 m). The CO₂ droplets dissolved gradually to become small flakes of CO₂ hydrate while rising, and these ascending flakes were found to disappear at 679 m depth. Although a pH as low as 5 was detected just above the liquid CO₂ venting site on the seafloor, no detectable pH depression in the water column ambient to the rising CO₂ droplets was observed. The results of the pH mapping survey showed only localized pH depression over the CO₂ venting site.     

Integration and evaluation of a power plant with a CaO-based CO2 capture system

This paper explores the integration and evaluation of a power plant with a CaO-based CO₂ capture system. There is a great amount of recoverable heat in the CaO-based CO₂ capture process. Five cases for the possible integration of a 600 MW power plant with CaO-based CO₂ capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8 MW but also results in the system with the lowest net power output of 446 MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400 MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846 MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3 €/MWh and the lowest cost of CO₂ avoided of 28.9 €/tCO₂. This new built steam cycle will not affect the operation of the reference plant which vents its CO₂ to the atmosphere, highly reducing the connection between the CO₂ capture process and the reference plant which vents its CO₂ to the atmosphere. The average cost of electricity and the cost of CO₂ avoided of the five cases are about 58.9 €/kWh and 35.9 €/tCO₂, respectively.     

CO2 recycling by reaction with renewably-generated hydrogen

A laboratory-scale reactor system was built and operated to demonstrate the feasibility of catalytically reacting carbon dioxide (CO₂) with renewably-generated hydrogen (H₂) to produce methane (CH₄) according to the Sabatier reaction: CO₂ + 4H₂ → CH₄ + 2H₂O. A cylindrical reaction vessel packed with a commercial methanation catalyst (Haldor Topsøe PK-7R) was used. Renewable H₂ produced by electrolysis of water (from solar- and wind-generated electricity) was fed into the reactor along with a custom blend of 2% CO₂ in N₂, meant to represent a synthetic exhaust mixture. Reaction conditions of temperature, flow rates, and gas mixing ratios were varied to determine optimum performance. The extent of reaction was monitored by real-time measurement of CO₂ and CH₄. Maximum conversion of CO₂ occurred at 300–350 °C. Approximately 60% conversion of CO₂ was realized at a space velocity of about 10,000 h^?1 with a molar ratio of H₂/CO₂ of 4/1. Somewhat higher total CO₂ conversion was possible by increasing the H₂/CO₂ ratio, but the most efficient use of available H₂ occurs at a lower H₂/CO₂ ratio.     

Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Novel lithium-based sorbents from fly ashes for CO2 capture at high temperatures

In this work several Li₄SiO₄-based sorbents from fly ashes for CO₂ capture at high temperatures have been developed. Three fly ash samples were collected and subjected to calcination at 950 °C in the presence of Li₂CO₃. Both pure Li₄SiO₄ and fly ash-based sorbents were characterised and tested for CO₂ sorption at different temperatures between 400 and 650 °C and adding different amounts of K₂CO₃ (0–40 mol%). To examine the sorbents performance, multiple CO₂ sorption/desorption cycles were carried out. The temperature and the presence of K₂CO₃ strongly affect the CO₂ sorption capacity for the sorbents prepared from fly ashes. When the sorption temperature increases by up to 600 °C both the CO₂ sorption capacity and the sorption rate increase significantly. Moreover when the amount of K₂CO₃ increases, the CO₂ sorption capacity also increases. At optimal experimental conditions (600 °C and 40 mol% K₂CO₃), the maximum CO₂ sorption capacity for the sorbent derived from fly ash was 107 mg CO₂/g sorbent. The Li₄SiO₄-based sorbents can maintain its original capacity during 10 cycle processes and reach the plateau of maximum capture capacity in less than 15 min, while pure Li₄SiO₄ presents a continual upward tendency for the 15 min of the capture step and attains no equilibrium capacity.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Rate modeling of CO2 stripping from potassium carbonate promoted by piperazine

This work presents results from a rate-based model of strippers at normal pressure (160 kPa) and vacuum (30 kPa) in Aspen Custom Modeler^® (ACM) for the desorption of CO₂ from 5 m K⁺/2.5 m piperazine (PZ). The model solves the material, equilibrium, summation and enthalpy (MESH) equations, the heat and mass transfer rate equations, and computes the reboiler duty and equivalent work for the stripping process. Simulations were performed with IMTP #40 random packing and a temperature approach on the hot side of the cross-exchanger of 5 °C and 10 °C. A “short and fat” stripper requires 7–15% less total equivalent work than a “tall and skinny” one because of the reduced pressure drop. The vacuum and normal pressure strippers require 230 s and 115 s of liquid retention time to get an equivalent work 4% greater than the minimum work. Stripping at 30 kPa was controlled by mass transfer with reaction in the boundary layer and diffusion of reactants and products (88% resistance at the rich end and 71% resistance at the lean end). Stripping at 160 kPa was controlled by mass transfer with equilibrium reactions (84% resistance at the rich end and 74% resistance at the lean end) at 80% flood. The typical predicted energy requirement for stripping and compression to 10 MPa to achieve 90% CO₂ removal was 37 kJ/gmol CO₂. This is about 25% of the net output of a 500 MW power plant with 90% CO₂ removal.