3D geomechanical modelling for CO2 geologic storage in the Dogger carbonates of the Paris Basin

CO₂ injection into a depleted hydrocarbon field or aquifer may give rise to a variety of coupled physical and chemical processes. During CO₂ injection, the increase in pore pressure can induce reservoir expansion. As a result the in situ stress field may change in and around the reservoir. The geomechanical behaviour induced by oil production followed by CO₂ injections into an oil field reservoir in the Paris Basin has been numerically modelled. This paper deals with an evaluation of the induced deformations and in situ stress changes, and their potential effects on faults, using a 3D geomechanical model. The geomechanical analysis of the reservoir–caprock system was carried out as a feasibility study using pressure information in a “one way” coupling, where pressures issued from reservoir simulations were integrated as input for a geomechanical model. The results show that under specific assumptions the mechanical effects of CO₂ injection do not affect the mechanical stability of the reservoir–caprock system. The ground vertical movement at the surface ranges from ?2 mm during oil production to +2.5 mm during CO₂ injection. Furthermore, the changes in in situ stresses predicted under specific assumptions by geomechanical modelling are not significant enough to jeopardize the mechanical stability of the reservoir and caprock. The stress changes issued from the 3D geomechanical modelling are also combined with a Mohr–Coulomb analysis to determine the fault slip tendency. By integrating the stress changes issued from the geomechanical modelling into the fault stability analysis, the critical pore pressure for fault reactivation is higher than calculated for the fault stability analysis considering constant horizontal stresses.     

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.     

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.     

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.     

Treatment of landfill leachates by nanofiltration

Landfill leachate contains high concentrations of organic matter, color, heavy metals and toxic substances. This study presents the feasibility of a commercial nanofiltration membrane (NF-300) in the removal of pollutants from a landfill leachate generated from the Treatment Stabilization and Disposal Facility in Gujarat state of India. Two different leachate samples (Leachates A and B) were collected from the downstream side of closed landfill cells A and B. The average quality of the leachate was 67 719 mg/L COD, 217 mg/L ammonical nitrogen, 22 418 mg/L BOD, 3847 mg/L chlorides and 909 mg/L sulphate. The operating variables studied were applied pressure (4–20 atm), feed flowrate (5–15 L/min) and pH (2, 4, 5.5 and 6.7). It was observed that the solute rejection (R_O) increased with increase in feed pressure and decreased with increase in feed concentration at constant feed flowrate. In the present study, the rejection of cations followed the sequence: R_O (Cr³⁺) > R_O (Ni²⁺) > R_O (Zn²⁺) > R_O (Cu²⁺) > R_O (Cd²⁺) for leachates A and B. The order of solute rejection sequence is inversely proportional to the diffusion coefficients. The rejection of sulphate ions by the NF-300 membrane was 83 and 85%, while the rejection of chlorides was 62 and 65% for leachates A and B, respectively. The NF-300 membrane was characterized by using the combined-film theory-Spiegler–Kedem (CFSK) model based on irreversible thermodynamics and the ion transport model based on the extended Nernst–Planck equation. The membrane transport parameters were estimated using the Levenberg–Marquadt method. The estimated parameters were used to predict the membrane performance and the predicted values are in good agreement with the experimental results.     

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.     

Capture of carbon dioxide from flue or fuel gas mixtures by clathrate crystallization in a silica gel column

A column of silica gel was employed to contact water with flue gas (CO₂/N₂) mixture to assess if CO₂ can be separated by hydrate crystallization. Three different silica gels were used. One with a pore size of 30 nm (particle size 40–75 μm) and two with a pore size of 100 nm and particle sizes of 40–75 and 75–200 μm respectively. The observed trends indicate that larger pores and particle size increase the gas consumption, CO₂ recovery, separation factor and water conversion to hydrate. Thus, the gel (gel #3) with the larger particle size and larger pore size was chosen to carry out experiments with concentrated CO₂ mixtures and for experiments in the presence of tetrahydrofuran (THF), which itself is a hydrate forming substance. Addition of THF reduces the operating pressure in the crystallizer but it also reduces the gas uptake. Gel #3 was also used in experiments with a fuel gas (CO₂/H₂) mixture in order to recover CO₂ and H₂. It was found that the gel column performs as well as a stirred reactor in separating the gas components from both flue gas and fuel gas mixtures. However, the crystallization rate and hydrate yield are considerably enhanced in the former. Finally the need for stirring is eliminated with the gel column which is enormously beneficial economically.     

Wellbore integrity analysis of a natural CO2 producer

Long-term integrity of existing wells in a CO₂-rich environment is essential for ensuring that geological sequestration of CO₂ will be an effective technology for mitigating greenhouse gas-induced climate change. The potential for wellbore leakage depends in part on the quality of the original construction as well as geochemical and geomechanical stresses that occur over its life-cycle. Field data are essential for assessing the integrated effect of these factors and their impact on wellbore integrity, defined as the maintenance of isolation between subsurface intervals. In this report, we investigate a 30-year-old well from a natural CO₂ production reservoir using a suite of downhole and laboratory tests to characterize isolation performance.These tests included mineralogical and hydrological characterization of 10 core samples of casing/cement/formation, wireline surveys to evaluate well conditions, fluid samples and an in situ permeability test. We find evidence for CO₂ migration in the occurrence of carbonated cement and calculate that the effective permeability of an 11′-region of the wellbore barrier system was between 0.5 and 1 milliDarcy. Despite these observations, we find that the amount of fluid migration along the wellbore was probably small because of several factors: the amount of carbonation decreased with distance from the reservoir, cement permeability was low (0.3–30 microDarcy), the cement–casing and cement-formation interfaces were tight, the casing was not corroded, fluid samples lacked CO₂, and the pressure gradient between reservoir and caprock was maintained. We conclude that the barrier system has ultimately performed well over the last 3 decades. These results will be used as part of a broader effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO₂ storage sites.     

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.     

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.     

Incidence of the level of deconstruction on material reuse,recycling and recovery from end-of life vehicles: an industrial-scale experimental study

The European Union has set ambitious objectives for the recovery rates of end-of life vehicles (ELVs). The directive 2000/53/CE (DIR, 2000) states that by 1st January 2015 at least 95% of the mass of an ELV must be reused and recovered, of which a maximum of 10% should be in the form of energy.In order to identify the key factors for improving the rate of material reuse, recycling and recovery of ELVs, ACYCLEA (PRAXY group) launched the “OPTIVAL VHU (ELV)” research program in collaboration with INSA Lyon in 2009. Three experimental campaigns were conducted on the industrial site of ACYCLEA to compare different scenarios of deconstruction. The campaigns were done on samples of 90 ELVs. The average mass (M_ELV) and age were estimated at 989 kg/ELV and 14 years, respectively. This article presents the results concerning the material balances of the successive operations. The contribution of each stage of the treatment (namely (i) depollution, (ii) deconstruction, and (iii) shredding and sorting operations) to the rate of recycling, reuse and recovery was calculated.Results showed firstly that the contribution of the operations of depollution was low (3.6 ± 0.1% of the mass of vehicles). The contribution of the operations of deconstruction was higher and increased logically with the degree of deconstruction. It ranged from 5% of M_ELV for the minimal level of deconstruction (campaign 1) to almost 10% with the highest level of deconstruction (campaign 3). The specific contribution of the operations of deconstruction to the rate of metal recycling was found to be quite low however, in the range of 2.6–2.8% of M_ELV, Shredding and post-shredding sorting operations enabled the recovery of the largest amounts of recyclable materials but no significant differences were observed between the overall recovery rates in the three campaigns (results ranged from 67 to 70% of M_ELV). Differences were observed however, for specific fractions such as the automotive shredder residues whose recovery rate was 16.3 ± 0.7%, 13.0 ± 0.5%, and 12.8 ± 0.2% for campaigns 1, 2 and 3, respectively. A larger production of non-ferromagnetic fraction was also observed in campaign 3, probably due to the extraction of the textiles during the dismantling operations which improved the efficiency of post-shredding sorting operations.The highest overall rate of reuse, recycling and energy recovery obtained in this study with the most rigorous approach was 81.5 ± 0.6% of the average mass of the ELV even with the highest level of deconstruction. It therefore appears that the European regulatory target of 95% would be difficult to achieve in 2015, except with a much greater optimization of the sorting technologies and the development of recycling processes.     

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).     

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).     

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.     

Optimization of Fenton oxidation pre-treatment for B. thuringiensis – Based production of value added products from wastewater sludge

Fenton oxidation pretreatment was investigated for enhancement of biodegradability of wastewater sludge (WWS) which was subsequently used as substrate for the production of value- added products. The Response surface method with fractional factorial and central composite designs was applied to determine the effects of Fenton parameters on solubilization and biodegradability of sludge and the optimization of the Fenton process. Maximum solubilization and biodegradability were obtained as 70% and 74%, respectively at the optimal conditions: 0.01 ml H₂O₂/g SS, 150 [H₂O₂]₀/[Fe²⁺]₀, 25 g/L TS, at 25 °C and 60 min duration. Further, these optimal conditions were tested for the production of a value added product, Bacillus thuringiensis (Bt) which is being used as a biopesticide in the agriculture and forestry sector. It was observed that Bt growth using Fenton oxidized sludge as a substrate was improved with a maximum total cell count of 1.63 × 10⁹ CFU ml^?1 and 96% sporulation after 48 h of fermentation. The results were also tested against ultrasonication treatment and the total cell count was found to be 4.08 × 10⁸ CFU ml^?1 with a sporulation of 90%. Hence, classic Fenton oxidation was demonstrated to be a rather more promising chemical pre-treatment for Bt - based biopesticide production using WWS when compared to ultrasonication as a physical pre-treatment.     

Carbon dioxide capture with concentrated,aqueous piperazine

Concentrated, aqueous piperazine (PZ) has been investigated as a novel amine solvent for carbon dioxide (CO₂) absorption. The CO₂ absorption rate of aqueous PZ is more than double that of 7 m MEA and the amine volatility at 40 °C ranges from 11 to 21 ppm. Thermal degradation is negligible in concentrated, aqueous PZ up to a temperature of 150 °C, a significant advantage over MEA systems. Oxidation of concentrated, aqueous PZ is appreciable in the presence of copper (4 mM), but negligible in the presence of chromium (0.6 mM), nickel (0.25 mM), iron (0.25 mM), and vanadium (0.1 mM). Initial system modeling suggests that 8 m PZ will use 10–20% less energy than 7 m MEA. The fast mass transfer and low degradation rates suggest that concentrated, aqueous PZ has the potential to be a preferred solvent for CO₂ capture.     

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.     

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.     

Hydrate formation during CO2 transport: Predicting water content in the fluid phase in equilibrium with the CO2-hydrate

In order to evaluate the risk of hydrate formation in CO₂ transport one has to be able to predict the water content in the fluid phase in equilibrium with the CO₂-hydrate. A literature review has identified some knowledge gaps, for example, there are no results available at temperatures lower than 243.15 K (?30 °C); and none of the models found in literature predicts the water content with high accuracy. A model based on equality of water fugacity in fluid and hydrate phase is presented here and used for the predictions of water content in equilibrium with hydrates. Although this model gives better accuracy in the overall temperature and pressure ranges of measurements than the models found in the literature, it is not accurate enough to satisfy the requirements of CO₂ transport. The simulation results also show that it is possible to form hydrate at low water content, such as x_w = 50 vppm, if temperature is low enough. In order to verify the results and improve the model accuracy further, more experimental data in a larger temperature and pressure region are required.     

CCS scenarios optimization by spatial multi-criteria analysis: Application to multiple source sink matching in Hebei province

A method, based on spatial analysis of the different criteria to be taken into consideration for building scenarios of CO₂ capture and storage (CCS), has been developed and applied to real case studies in the Hebei province. Totally 88 point sources (42 from power sector, 9 from iron and steel, 18 from cement, 16 from ammonia, and 3 from oil refinery) are estimated and their total emission amounts to 231.7 MtCO₂/year with power, iron and steel, cement, ammonia and oil refinery sharing 59.13%, 25.03%, 11.44%, 3.5%, and 0.91%, respectively. Storage opportunities can be found in Hebei province, characterised by a strong tectonic subsidence during the Tertiary, with several kilometres of accumulated clastic sediments. Carbon storage potential for 25 hydrocarbon fields selected from the Huabei complex is estimated as 215 MtCO₂ with optimistic assumption that all recovered hydrocarbon could be replaced by an equivalent volume of CO₂ at reservoir conditions. Storage potential for aquifers in the Miocene Guantao formation is estimated as 747 MtCO₂ if closed aquifer assumed or 371 MtCO₂ if open aquifer and single highly permeable horizon assumed. Due to poor knowledge on deep hydrogeology and to pressure increase in aquifer, injecting very high rates requested by the major CO₂ sources (>10 MtCO₂/year) is the main challenge, therefore piezometry and discharge must be carefully controlled. A source sink matching model using ArcGIS software is designed to find the least-cost pathway and to estimate transport route and cost accounting for the additional costs of pipeline construction due to landform and land use. Source sink matching results show that only 15–25% of the emissions estimated for the 88 sources can be sequestrated into the hydrocarbon fields and the aquifers if assuming sinks should be able to accommodate at least 15 years of the emissions of a given source.