CO2SINK—From site characterisation and risk assessment to monitoring and verification: One year of operational experience with the field laboratory for CO2 storage at Ketzin, Germany

The CO₂SINK pilot project at Ketzin is aimed at a better understanding of geological CO₂ storage operation in a saline aquifer. The reservoir consists of fluvial deposits with average permeability ranging between 50 and 100 mDarcy. The main focus of CO₂SINK is developing and testing of monitoring and verification technologies. All wells, one for injection and two for observation, are equipped with smart casings (sensors behind casing, facing the rocks) containing a Distributed Temperature Sensing (DTS) and electrodes for Electrical Resistivity Tomography (ERT). The in-hole Gas Membrane Sensors (GMS) observed the arrival of tracers and CO₂ with high temporal resolution. Geophysical monitoring includes Moving Source Profiling (MSP), Vertical Seismic Profiling (VSP), crosshole, star and 4-D seismic experiments. Numerical models are benchmarked via the monitoring results indicating a sufficient match between observation and prediction, at least for the arrival of CO₂ at the first observation well. Downhole samples of brine showed changes in the fluid composition and biocenosis. First monitoring results indicate anisotropic flow of CO₂ coinciding with the “on-time” arrival of CO₂ at observation well one (Ktzi 200) and the later arrival at observation well two (Ktzi 202). A risk assessment was performed prior to the start of injection. After one year of operations about 18,000 t of CO₂ were injected safely.     

Analytical solution for Joule–Thomson cooling during CO2 geo-sequestration in depleted oil and gas reservoirs

Mathematical tools are needed to screen out sites where Joule–Thomson cooling is a prohibitive factor for CO₂ geo-sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO₂ injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kg s^?1 (0.1 MT yr^?1) into moderately warm (>40 °C) and permeable formations (>10^?14 m² (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as 2 MPa (290 psi).     

Hydraulic characterisation of the Stuttgart formation at the pilot test site for CO2 storage, Ketzin, Germany

The paper presents an approach for the interpretation of hydraulic tests of a CO₂ storage reservoir. The sandstone reservoir is characterised by a fluviatile channel structure embedded in a low-permeability matrix. Pumping tests were carried out in three wells, with simultaneous pressure monitoring in each well.The hydraulic parameters (permeability and storativity) and the boundary configurations were calibrated using three different approaches: (i) parameter calibration and type curve interpretation for single-hole tests, (ii) calibration of the entire build-up phase for cross-hole tests, and (iii) calibration of the initial pressure response for cross-hole pumping tests. In addition, the arrival time of the pressure response was determined and provides additional information about the pathways of hydraulic connection.The measured pumping test permeabilities of the formation were much lower than those measured on the cores, which is very unusual. The pumping test permeabilities are mainly between 50 mD and 100 mD (millidarcy), while core samples show a mean aquifer permeability of 500–1100 mD. Based on this it was concluded that some kind of continuous low-permeability structure exists, which was supported by core material. Three possible aquifer configurations were considered. The first and second were derived from traditional pumping test analysis and were conceptualised using flow boundaries. Each of the analyses provides a different result. A method was developed in which these differences were resolved by interpreting the pressure response with respect to its spatial and temporal sensitivity. This solution lead to a third configuration which was mainly based on spatially-variable permeabilities. Taking into account the pumping test results, the geological background and the behaviour of injected CO₂, we consider only the third configuration to be realistic. The results are in good agreement with modelled CO₂ arrival times and pressure history.     

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.     

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.     

Experimental investigation of the CO2 sealing efficiency of caprocks

Using a combination of experimental (petrophysical and mineralogical) methods, the effects of high-pressure CO₂ exposure on fluid transport properties and mineralogical composition of two pelitic caprocks, a limestone and a clay-rich marl lithotype have been studied. Single and multiphase permeability tests, gas breakthrough and diffusion experiments were conducted under in situ p/T conditions on cylindrical plugs (28.5 mm diameter, 10–20 mm thickness).The capillary CO₂ sealing efficiency of the initially water-saturated sample plugs was found to decrease in repetitive gas breakthrough experiments on the same sample from 0.74 to 0.41 MPa for the limestone and from 0.64 to 0.43 MPa for the marl. Helium breakthrough experiments before and after the CO₂ tests showed a decrease in capillary threshold (snap-off) pressure from 1.81 to 0.62 MPa for the limestone.Repetitive CO₂ diffusion experiments on the marlstone revealed an increase in the effective diffusion coefficient from 7.8 × 10^?11 to 1.2 × 10^?10 m².Single-phase (water) permeability coefficients derived from steady-state permeability tests ranged between 7 and 56 nano-Darcy and showed a consistent increase after each CO₂ test cycle. Effective gas permeabilities were generally one order of magnitude lower than water permeabilities and exhibit the same trend. XRD measurements performed before and after exposure to CO₂ did not reveal any distinct change in the mineral composition for both samples. Similarly, no significant changes were observed in specific surface areas (determined by BET) and pore-size distributions (determined by mercury injection porosimetry). High-pressure CO₂ sorption experiments on powdered samples revealed significant CO₂ sorption capacities of 0.27 and 0.14 mmol/g for the marlstone and the limestone, respectively.The changes in transport parameters in the absence of detectable mineral alterations may be explained by carbonate dissolution and further precipitation along a pH profile across the sample plug which would not be subject to quantitative mineral alteration.     

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.     

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.     

Energy balances,greenhouse gas emissions and economics of biochar production from palm oil empty fruit bunches

This paper presents results from a gate-to-gate analysis of the energy balance, greenhouse gas (GHG) emissions and economic efficiency of biochar production from palm oil empty fruit bunches (EFB). The analysis is based on data obtained from EFB combustion in a slow pyrolysis plant in Selangor, Malaysia. The outputs of the slow pyrolysis plant are biochar, syngas, bio-oil and water vapor. The net energy yield of the biochar produced in the Selangor plant is 11.47 MJ kg⁻¹ EFB. The energy content of the biochar produced is higher than the energy required for producing the biochar, i.e. the energy balance of biochar production is positive. The combustion of EFB using diesel fuel has the largest energy demand of 2.31 MJ kg⁻¹ EFB in the pyrolysis process. Comparatively smaller amounts of energy are required as electricity (0.39 MJ kg⁻¹ EFB) and for transportation of biochar to the warehouse and the field (0.13 MJ kg⁻¹ EFB). The net greenhouse gas emissions of the studied biochar production account for 0.046 kg CO₂-equiv. kg⁻¹ EFB yr⁻¹ without considering fertilizer substitution effects and carbon accumulation from biochar in the soil. The studied biochar production is profitable where biochar can be sold for at least 533 US-$ t⁻¹. Potential measures for improvement are discussed, including higher productivity of biochar production, reduced energy consumption and efficient use of the byproducts from the slow pyrolysis.     

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.     

Assessment of basin-scale hydrologic impacts of CO2 sequestration,Illinois basin

Idealized, basin-scale sharp-interface models of CO₂ injection were constructed for the Illinois basin. Porosity and permeability were decreased with depth within the Mount Simon Formation. Eau Claire confining unit porosity and permeability were kept fixed. We used 726 injection wells located near 42 power plants to deliver 80 million metric tons of CO₂/year. After 100 years of continuous injection, deviatoric fluid pressures varied between 5.6 and 18 MPa across central and southern part of the Illinois basin. Maximum deviatoric pressure reached about 50% of lithostatic levels to the south. The pressure disturbance (>0.03 MPa) propagated 10–25 km away from the injection wells resulting in significant well–well pressure interference. These findings are consistent with single-phase analytical solutions of injection. The radial footprint of the CO₂ plume at each well was only 0.5–2 km after 100 years of injection. Net lateral brine displacement was insignificant due to increasing radial distance from injection well and leakage across the Eau Claire confining unit. On geologic time scales CO₂ would migrate northward at a rate of about 6 m/1000 years. Because of paleo-seismic events in this region (M5.5–M7.5), care should be taken to avoid high pore pressures in the southern Illinois basin.     

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.     

Experimental assessment of brine and/or CO2 leakage through well cements at reservoir conditions

Two sets of experiments on typical Class G well cement were carried out in the laboratory to understand better the potential processes involved in well leakage in the presence of CO₂. In the first set, good-quality cement samples of permeability in the order of 0.1 μD (10^?19 m²) were subjected to 90 days of flow through with CO₂-saturated brine at conditions of pressure, temperature and water salinity characteristic of a typical geological sequestration zone. Cement permeability dropped rapidly at the beginning of the experiment and remained almost constant thereafter, most likely mainly as a result of CO₂ exsolution from the saturated brine due to the pressure drop along the flow path which led to multi-phase flow, relative-permeability effects and the observed reduction in permeability. These processes are identical to those which would occur in the field as well if the cement sheath in the wellbore annulus is of good quality. The second set of experiments, carried out also at in situ conditions and using ethane rather than CO₂ to eliminate any possible geochemical effects, assessed the effect of annular spaces between wellbore casing and cement, and of radial cracks in cement on the effective permeability of the casing-cement assemblage. The results show that, if both the cement and the bond are of good quality, the effective permeability of the assemblage is extremely low (in the order of 1 nD, or 10^?21 m²). The presence of an annular gap and/or cracks in the order of 0.01–0.3 mm in aperture leads to a significant increase in effective permeability, which reaches values in the range of 0.1–1 mD (10^?15 m²). The results of both sets of experiments suggest that good cement and good bonding with casing and the surrounding rock will likely constitute a good and reliable barrier to the upward flow of CO₂ and/or CO₂-saturated brine. The presence of mechanical defects such as gaps in bonding between the casing or the formation, or cracks in the cement annulus itself, leads to flow paths with significant effective permeability. This indicates that the external and internal interfaces of cements in wells would most probably constitute the main flow pathways for fluids leakage in wellbores, including both gaseous/supercritical phase CO₂ and CO₂-saturated brine.     

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.     

Techno-economic evaluation of biogas upgrading process using CO2 facilitated transport membrane

The biogas upgrading by membrane separation process using a highly efficient CO₂-selective polyvinylamine/polyvinylalcohol (PVAm/PVA) blend membrane was investigated by experimental study and simulation with respect to process design, operation optimization and economic evaluation. This blend membrane takes advantages of the unique CO₂ facilitated transport from PVAm and the robust mechanical properties from PVA, exhibits both high CO₂/CH₄ separation efficiency and very good stability. CO₂ transports through the water swollen membrane matrix in the form of bicarbonate. CO₂/CH₄ selectivity up to 40 and CO₂ permeance up to 0.55 m³(STP)/m² h bar at 2 bar were documented in lab with synthesized biogas (35% CO₂ and 65% CH₄). Membrane performances at varying feed pressures were recorded and used as the simulation basis in this work. The process simulation of an on-farm scale biogas upgrading plant (1000 Nm³/h) was conducted. Processes with four different membrane module configurations with or without recycle were evaluated technically and economically, and the 2-stage in cascade with recycle configuration was proven optimal among the four processes. The sensitivity of the process to various operation parameters was analyzed and the operation conditions were optimized.     

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.     

Coupled reservoir-geomechanical analysis of CO2 injection and ground deformations at In Salah,Algeria

In Salah Gas Project in Algeria has been injecting 0.5–1 million tonnes CO₂ per year over the past 5 years into a water-filled strata at a depth of about 1800–1900 m. Unlike most CO₂ storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20 m. To ensure adequate CO₂ flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1–1.5 km) horizontal injection wells. In an ongoing research project we use field data and coupled reservoir-geomechanical numerical modeling to assess the effectiveness of this approach and to investigate monitoring techniques to evaluate the performance of a CO₂ injection operation in relatively low-permeability formations. Among the field data used are ground surface deformations evaluated from recently acquired satellite-based inferrometry (InSAR). The InSAR data shows a surface uplift on the order of 5 mm per year above active CO₂ injection wells and the uplift pattern extends several km from the injection wells. In this paper we use the observed surface uplift to constrain our coupled reservoir-geomechanical model and conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. The results of our analysis indicate that most of the observed uplift magnitude can be explained by pressure-induced, poro-elastic expansion of the 20-m-thick injection zone, but there could also be a significant contribution from pressure-induced deformations within a 100-m-thick zone of shaly sands immediately above the injection zone.     

A 13C NMR investigation of CO2 absorption and desorption in aqueous 2,2′-iminodiethanol and N-methyl-2,2′-iminodiethanol

The carbon dioxide capture and release from aqueous 2,2′-iminodiethanol (DEA) and N-methyl-2,2′-iminodiethanol (MDEA) have been investigated by means of ¹³C NMR spectroscopy. We have designed two experimental procedures using a gas mixture containing 12% (v/v) CO₂ in N₂ or air and 0.667 M aqueous solutions of DEA and MDEA. To understand the CO₂–amine reaction equilibria, separate experiments of CO₂ absorption (at 293, 313 and 333 K) and desorption (at boiling temperature, room pressure) were carried out. The ¹³C NMR analysis has allowed us to establish: (1) the percentage of CO₂ stored in solution as HCO₃^?, CO₃^2? and DEA carbamate; (2) the formation of DEA carbamate as a function of absorption temperature and time; (3) the slower decomposition of DEA carbamate than that of bicarbonate. In the experiments planned to test the reuse of the regenerated amines, the absorbent solution was continuously circulated in a closed cycle while it was absorbing CO₂ in the absorber (set at 293 K) and simultaneously regenerating amine in the desorber (set at 388 K). After the equilibrium has been reached (13 h), the CO₂ absorption efficiency is comprised between 84.0% (DEA) and 82.6% (MDEA) and the average amine regeneration efficiency ranges between 69.6% (DEA) and 78.2% (MDEA). Additionally, MDEA is more stable towards thermal degradation than DEA.     

1D and 2D absorption-rate/kinetic modeling and simulation of carbon dioxide absorption into mixed aqueous solutions of MDEA and PZ in a laminar jet apparatus

The kinetics of the reaction between carbon dioxide (CO₂) and mixed solutions of methyldiethanolamine (MDEA) and piperazine (PZ) was investigated experimentally in a laminar jet apparatus. The experimental kinetic data were obtained under no interfacial turbulence and over a temperature range from 313 to 333 K, MDEA/PZ wt% concentration ratios of 27/3, 24/6 and 21/9, and CO₂ loadings from 0.0095 to 0.33 mol CO₂/mol amine. In addition, a new absorption-rate/kinetics model for the kinetics of the mixed of solvents was developed, which takes into account the coupling between chemical equilibrium, mass transfer, and all possible chemical reactions involved in the CO₂ reaction with MDEA/PZ solvent. The partial differential equations of this model were solved by the finite element numerical method (FEM) based on COMSOL software. The obtained experimental kinetics data were used to obtain the kinetic parameters of CO₂ absorption into MDEA/PZ solutions. The reaction-rate constant obtained for PZ blended with MDEA was kPZ = 2.572 × 10¹² exp(?5211/T). The 2D model for the blended amines MDEA/PZ has revealed the concentration profiles of all the species in both the radial and axial directions of the laminar jet which has enabled a better understanding of the correct sequence in which the reaction steps involved in the reactive absorption of CO₂ in aqueous mixed MDEA/PZ solution occur. It also revealed that PZ may be depleted by the time the solvent blend of MDEA/PZ with a loading greater than 0.015 mol/mol amine is exposed to CO₂ from the top of the laminar jet absorber.     

Lead accumulation in different Chinese cabbage cultivars and screening for pollution-safe cultivars

Recently, the concept of pollution-safe cultivars (PSCs) was proposed to minimize the influx of pollutants to the human food chain. Variations in lead (Pb) uptake and translocation among Chinese cabbage (Brassica pekinensis L.) cultivars were investigated in a pot-culture experiment and a field-culture experiment to screen out Pb-PSCs for food safety. The results of the pot-culture experiment showed that shoot Pb concentrations under two Pb treatments (500 and 1500 mg kg^?1) varied significantly (p < 0.05) between cultivars, with average values of 3.01 and 6.87 mg kg^?1, respectively. Enrichment factors (EFs) and translocation factors (TFs) in cultivars were less than 0.50 and varied significantly (p < 0.05) between cultivars. Shoot Pb concentrations in 12 cultivars under treatment T₁ (500 mg kg^?1) were lower than 2.0 mg kg^?1. The field-culture experiment further confirmed Qiuao, Shiboqiukang and Fuxing 80 as Pb-PSCs, which were suitable to be cultivated in low-Pb (<382.25 mg kg^?1) contaminated soils and harmless to human health as foods.