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.     

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.     

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.     

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).     

Biofilm enhanced geologic sequestration of supercritical CO2

In order to develop subsurface CO₂ storage as a viable engineered mechanism to reduce the emission of CO₂ into the atmosphere, any potential leakage of injected supercritical CO₂ (SC-CO₂) from the deep subsurface to the atmosphere must be reduced. Here, we investigate the utility of biofilms, which are microorganism assemblages firmly attached to a surface, as a means of reducing the permeability of deep subsurface porous geological matrices under high pressure and in the presence of SC-CO₂, using a unique high pressure (8.9 MPa), moderate temperature (32 °C) flow reactor containing 40 millidarcy Berea sandstone cores. The flow reactor containing the sandstone core was inoculated with the biofilm forming organism Shewanella fridgidimarina. Electron microscopy of the rock core revealed substantial biofilm growth and accumulation under high-pressure conditions in the rock pore space which caused >95% reduction in core permeability. Permeability increased only slightly in response to SC-CO₂ challenges of up to 71 h and starvation for up to 363 h in length. Viable population assays of microorganisms in the effluent indicated survival of the cells following SC-CO₂ challenges and starvation, although S. fridgidimarina was succeeded by Bacillus mojavensis and Citrobacter sp. which were native in the core. These observations suggest that engineered biofilm barriers may be used to enhance the geologic sequestration of atmospheric CO₂.     

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.     

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.     

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.     

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.     

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.     

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.     

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.     

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.     

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.     

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.     

Testing of hydrotalcite-based sorbents for CO2 and H2S capture for use in sorption enhanced water gas shift

The feasibility of the sorption enhanced water gas shift (SEWGS) process under sour conditions is shown. The sour-SEWGS process constitutes a second generation pre-combustion carbon capture technology for the application in an IGCC. As a first critical step, the suitability of a K₂CO₃ promoted hydrotalcite-based CO₂ sorbent is demonstrated by means of adsorption and regeneration experiments in the presence of 2000 ppm H₂S. In multiple cycle experiments at 400 °C and 5 bar, the sorbent displays reversible co-adsorption of CO₂ and H₂S. The CO₂ sorption capacity is not significantly affected compared to sulphur-free conditions. A mechanistic model assuming two different sites for H₂S interaction explains qualitatively the interactions of CO₂ and H₂S with the sorbent. On the type A sites, CO₂ and H₂S display competitive sorption where CO₂ is favoured. The type B sites only allow H₂S uptake and may involve the formation of metal sulphides. This material behaviour means that the sour-SEWGS process likely eliminates CO₂ and H₂S simultaneously from the syngas and that an almost CO₂ and H₂S-free H₂ stream and a CO₂ + H₂S stream can be produced.     

Experimental investigation of wellbore integrity and CO2–brine flow along the casing–cement microannulus

Wellbore integrity is one of the key performance criteria in the geological storage of CO₂. It is significant in any proposed storage site but may be critical to the suitability of depleted oil and gas reservoirs that may have 10’s to 1000’s of abandoned wells. Much previous work has focused on Portland cement which is the primary material used to seal wellbore systems. This work has emphasized the potential dissolution of Portland cement. However, an increasing number of field studies (e.g., Carey et al., 2007), experimental studies (e.g., Kutchko et al., 2006) and theoretical considerations indicate that the most significant leakage mechanism is likely to be flow of CO₂ along the casing–cement microannulus, cement–cement fractures, or the cement–caprock interface.In this study, we investigate the casing–cement microannulus through core-flood experiments. The experiments were conducted on a synthetic wellbore system consisting of a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing that had grooves to accommodate fluid flow. The experiments were conducted at 40 $°$ C and 14 MPa pore pressure for 394 h. During the experiment, 6.2 l of a 50:50 mixture of supercritical CO₂ and 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement–casing wellbore system. Approximately 59,000 pore volumes of fluid moved through the casing–cement grooves. Scanning electron microscopy revealed that the CO₂–brine mixture impacted both the casing and the cement. The Portland cement was carbonated to depths of 50–250 $\mu$m by a diffusion-dominated process. There was very little evidence for mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of mixed calcium and iron carbonate that lined the channels and in one case almost completely filled a channel. The depth of steel corroded was estimated at 25– $30\mu$m and was similar in value to results obtained with a simplified corrosion model.The experimental results were applied to field observations of carbonated wellbore cement by Carey et al. (2007) and Crow et al. (2009) to show that carbonation of the field samples was not accompanied by significant CO₂–brine flow at the casing–cement interface. The sensitivity of standard-grade steel casing to corrosion suggests that relatively straight-forward wireline logging of external casing corrosion could be used as a useful indicator of flow behind casing. These experiments also reinforce other studies that indicate rates of Portland cement deterioration are slow, even in the high-flux CO₂–brine experiments reported here.     

CO2 removal using membrane gas absorption

The objective of this study is to investigate the potential process for the removal of carbon dioxide (CO₂) from flue gas using fundamental membrane contactor, which is a membrane gas absorption (MGA) system. The experiments consisted of microporous polyvinylidenefluoride (PVDF) flat sheet membrane with 0.1 μm (as module I) and 0.45 μm (as module II) pore size. 2-Amino-2-methyl-1-propanol (AMP) solution was employed as the liquid absorbent. The effect of AMP concentration was studied with variation in the range 1–5 M. In addition, the experiments were carried out with 10%, 20%, 30% and 40% gas ratio of CO₂ to N₂ and pure CO₂ as well. Through contact angle measurement, membranes for module I and module II were obtained with CA values of around 130.25° and 127.77°, respectively. The mass transfer coefficients for module II are lower than those of module I for 1–5 M of AMP. Furthermore, the increase in CO₂ concentration in the feed gas stream enhanced the CO₂ flux as the driving force of the system was increased in sequence from 1 M to 5 M of AMP. However, after the particular percentage (40%) of CO₂ inlet concentration, the CO₂ fluxes seem saturated. The combination of AMP as liquid absorbent and PVDF microporous membrane in MGA system has shown the potential to remove the CO₂ from flue gas. In addition, the higher AMP concentration gave higher mass transfer coefficient at low liquid flow rates.     

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.     

Pulverized coal stream ignition delay under conventional and oxy-fuel combustion conditions

The coal stream ignition process is critical to the performance of modern pulverized coal burners, particularly when operating under novel conditions such as experienced in oxy-fuel combustion. However, experimental studies of coal stream ignition are lacking, and recent modeling efforts have had to rely on comparisons with a single set of experiments in vitiated air. To begin to address this shortfall, we have conducted experiments on the ignition properties of two U.S. and two Chinese coals in a laminar entrained flow reactor. Most of the measurements focused on varying the coal feed rate for furnace temperatures of 1230–1320 K and for 12–20 vol.% O₂ in nitrogen. The influence of coal feed rate on ignition with a carbon dioxide diluent was also measured for 20 vol.% O₂ at 1280 K. A second set of measurements was performed for ignition of a fixed coal feed rate in N₂ and CO₂ environments at identical furnace temperatures of 1200 K, 1340 K, and 1670 K. A scientific CCD camera equipped with a 431 nm imaging filter was used to interrogate the ignition process. Under most conditions, the ignition delay decreased with increasing coal feed rate until a minimum was reached at a feed rate corresponding to a particle number density of approximately 4 × 10⁹ m^?3 in the coal feed pipe. This ignition minimum corresponds to a cold flow group number, G, of ～0.3. At higher coal feed rates the ignition delay increased. The ignition delay time was shown to be very sensitive to (a) the temperature of the hot coflow into which the coal stream is introduced, and (b) the coal particle size. The three high volatile bituminous coals showed nearly identical ignition delay as a function of coal feed rate, whereas the subbituminous coal showed slightly greater apparent ignition delay. Bath gas CO₂ content was found to have a minor impact on ignition delay.