Effects Of CO2 Injection Research Articles

Evaluation of Geo-Mechanical-Chemical Impacts of Co2 Injection to Depleted Oil Reservoirs

This paper presents a more holistic approach in evaluating the impacts of CO2 injection in CO2 sequestration operations in a depleted Morrow B sandstone of the Farnsworth Unit, Ochiltree County, Texas. The complex interactions between CO2 and the formation fluids (oil and brine) and the acidized brine interactions with formation rock when coupled with mechanical processes present an integrated and realistic effect of CO2 injection in the underground environment. In light of this, different coupled numerical simulation models were developed to investigate the various CO2 trapping mechanisms and the long-term fate of CO2 in a depleted Morrow B sandstone. The models include hydrodynamical model, coupled hydrodynamical-mechanical model, coupled hydrodynamical-chemical model, and coupled hydrodynamical-chemical-mechanical model. A WAG operation was carried out for 20 years after the history period and followed by a post-injection period of 1000 years to monitor and evaluate the effect of the injected CO2 on the underground environment. This work shows that geomechanics impacted the petrophysical properties of the reservoir and had significant impact on the injectivity of CO2. The chemical reactions had very little impact on the petrophysical properties of the reservoir. The different simulation scenarios resulted in variable amounts of storage within the partially depleted oil reservoir.

Investigation of Fluid-Injection-Induced Coal Stiffness Alteration using a Single-Core Multistage Triaxial Test

Nonlinear stress-strain behavior and failure envelopes are critical rock mechanical data for gas reservoir evaluation and development, especially when the basic rock properties are measured under actual reservoir conditions that include pore pressure. For coalbed methane (CBM) reservoirs, the mechanical properties of coal may be different under actual reservoir conditions because the in situ coal is fluid saturated. Multistage triaxial testing of coal can generate a full failure envelope using a single core instead of a set of destructive core tests—as is the case with single stage testing. This multistage technique is necessary because of the scarcity of actual reservoir specimens. Consequently, in this study, a series of multistage triaxial compression tests on a fluid-saturated coal specimen was conducted to determine the mechanical properties of reservoir coal formations as a function of confining stress and fluid compositions and pressures. An oven-dried coal core 50 mm in diameter and 100 mm in length was prepared. Different fluids were employed in the test, including the non-sorbing gas He and sorbing gases, such as N2, CH4 and CO2, and also H2O. Coal sorption behavior was investigated during the triaxial compression test, and the peak stresses under various pore pressures and confining pressure conditions were measured. In addition, the competition between the fluid-density-induced hardening and adsorption-induced softening of the coal core is discussed. The coal strength under gas-saturated conditions was sensitive to the confining pressure. The coal under a higher confining pressure exhibited a stiffer response and the peak load increased with higher confining pressure. Strength weakening due to gas adsorption was observed for N2, CH4, CO2, and water injection. Both CH4 and CO2 had a strong influence on coal stiffness alteration mainly because the higher adsorption capacity of coal for them. Stress-strain relationships behaved in a non-linear when a sorbing-gas was involved. The softening effect of CO2 injection was complicated by a CO2 phase change at higher pressure conditions. This study is applicable to a wide range of engineering applications, including reservoir stress response, permeability evolution, hydraulic fractures, coal mining, and borehole stability, and fault slipping.

Laboratory quantification of coal permeability reduction effect during carbon dioxide injection process

CO2 geo-sequestration in unminable coal seams is one promising method to mitigate greenhouse gas emissions and would be a means of cleaner production. At the same time, the injected CO2 can enhance coalbed methane recovery and offsets the economic cost for CO2 transportation and injection. However, this technology is still at its primary stage and so far, no large scale of field CO2 injection has been implemented. One of the main difficulties encountered in this process is the permeability reduction induced by CO2 injection and as a result, the injection rate is sharply dropped in the later period. In this paper, detailed laboratory experiments are conducted to investigate the permeability reduction effects during CO2 injections. The dynamic permeability reduction effects are measured with the continuous CO2 injection under different confining pressure conditions. Permeability reduction effects of 13 %–77 % are obtained with respect to the CO2 exposure time in different testings. In low permeability scenario, the permeability reduction effects are severer. Specifically, when the absolute permeability is 1mD, 0.42mD, 0.18mD and 0.03mD, the permeability reduction is 13 %, 36 %, 48 % and 77 %, respectively. Compared with the coal triaxial adsorption tests, it is suggested that the permeability equilibrium is not equal to the adsorption equilibrium. The triaxial adsorption equilibrium process takes much longer time than that of permeability equilibrium process. Based on the testing results, a novel dynamic permeability model is proposed to illustrate the permeability evolutions. The existence of weak internal surface influences the matrix strain and the permeability. This model is also validated by other’s experimental results and can be used for explaining coal seam permeability reduction effects of CO2 injection in coal seams.

An experimental description of the double positive effect of CO2 injection in methane hydrate deposits in terms of climate change mitigation

In this paper, the possibility of injecting CO2 into a hydrate reservoir, with the only aim of preventing methane release was investigated. Pure methane hydrates were formed and then partially dissociated, due to a provoked temperature increase of 2 °C. The same procedure was applied to a system composed by a core of CH4 hydrates and an external shell made with CO2 hydrates. In tests with only methane hydrate, that temperature increase caused partial hydrate dissociation, with a consequent increase in pressure about 7.81–8.42 bar. In presence of CO2 hydrate, the same temperature increase did not cause any dissociation, even if the new established condition were not suitable for CH4 hydrates stability. Results proved that CO2 is capable to form a strong hydrate shell around the methane core, which hinders its dissociation. Two positive contributions were reached: CO2 permanent storage and the prevention of CH4 release in the atmosphere.

The Effect of Carbonyl and Hydroxyl Compounds on Swelling Factor, Interfacial Tension, and Viscosity in CO2 Injection: A Case Study on Aromatic Oils

A factor influencing the effectiveness of CO2 injection is miscibility. Besides the miscible injection, CO2 may also contribute to oil recovery improvement by immiscible injection through modifying several properties such as oil swelling, viscosity reduction, and the lowering of interfacial tension (IFT). Moreover, CO2 immiscible injection performance is also expected to be improved by adding some solvent. However, there are a lack of studies identifying the roles of solvent in assisting CO2 injection through observing those properties simultaneously. This paper explains the effects of CO2–carbonyl and CO2–hydroxyl compounds mixture injection on those properties, and also the minimum miscibility pressure (MMP) experimentally by using VIPS (refers to viscosity, interfacial tension, pressure–volume, and swelling) apparatus, which has a capability of measuring those properties simultaneously within a closed system. Higher swelling factor, lower viscosity, IFT and MMP are observed from a CO2–propanone/acetone mixture injection. The role of propanone and ethanol is more significant in Sample A1, which has higher molecular weight (MW) of C7+ and lower composition of C1–C4, than that in the other Sample A9. The solvents accelerate the ways in which CO2 dissolves and extracts oil, especially the extraction of the heavier component left in the swelling cell.

A machine learning model for predicting the minimum miscibility pressure of CO2 and crude oil system based on a support vector machine algorithm approach

CO2 enhanced oil recovery (EOR) is a potential way for carbon capture, utilization and storage (CCUS). However, the effect of CO2 injection is greatly influenced by the reservoir conditions. Typically, Minimum miscible pressure (MMP) is selected as one of the key parameters for the screening and evaluation of prospective CO2 flooding. Conventional slim tube test is both accurate and widely accepted but it is inefficient. Existing empirical formulas for MMPs are easy to be used but have been proved inaccurate and unreliable. Machine learning-based methods have great advantages in predicting MMP. However, only predication accuracy is discussed for most models without the screening of the main control factors and further validation of the model reliability. In this paper, a new prediction model based on support vector machine (SVM) was developed for pure/impure CO2 and crude oil system. This study was based on 147 sets of MMP data from the literature with full information on reservoir temperature, oil composition and gas composition. The main control factors were screened by several statistical methods. Unlike the conventional prediction models that verified by only prediction accuracy, learning curve and single factor control variable analysis are further validated to obtain the optimum model.

CO2 injection improves the high-temperature performances of Cr-bearing vanadia-titania magnetite smelting in blast furnace

The effects of CO2 injection on the high-temperature metallurgical performance of Cr-bearing vanadia-titania magnetite (CVTM) in blast furnace (BF) smelting were investigated. The dry air or O2-enriched air is not necessarily suitable for any blast furnace production, and CO2-containing high-temperature energy-carried gas (CHEG) also can be an alternative injection gas with lower cost and pollution. This kind of CHEG can be blast furnace gas, basic oxygen furnace gas, coke oven gas, sintering gas and rotary kiln gas and so on, which contained high sensible heat and CO2, H2 and CO. Injecting CHEG into the blast furnace can replace air injection to achieve the heat balance in the cohesive zone and raceway. The calculated boundary injection ratio of CO2 is approximately 15.3%, and the experimental optimal CO2 injection ratio is about 10∼20%. CO2 injection benefits the blast furnace operation, the permeability of cohesive zone, recovery ratio of Cr and V. With increasing injected content of CO2, the temperature range of softening zone [T40-T4] and melting-dripping zone [Td-Ts] decrease almost 20℃, and the dripping ratio increases from 62.36% to 69.76%, the recovery of V increases from 32.75% to 47.96%, and the recovery of Cr increases from 42.35% to 64.41%. The CO2 injection affects the melting temperature of the high-titanium slags to be higher and the maximum temperature difference can reach 45℃, which is beneficial to the slag stability and separation of slag-iron and restrain the over-deduction of titania to TiN upon the slag-coke interface with lower N2.

An experimental and theoretical investigation of asphaltene precipitation in a crude oil from the Brazilian pre-salt layer under CO2 injection

The asphaltene onset pressure (AOP) is a key parameter to determine the flow assurance of oils. In this work we performed an experimental study of the PVT (pressure–volume-temperature) properties of a crude oil from the Brazilian pre-salt layer. First, dead-oil was recombined with natural gas at the reservoir gas-oil ratio (GOR). Then, different techniques (volumetric, visual, light-scattering and filtration) were used to measure the AOP and bubble pressure (BP) at temperatures in the range of (293.15 to 348.15) K. The effect of CO2 injection on both properties was also evaluated at reservoir temperature. Additional data of mass density was measured at reservoir pressure and temperature. The experimental data were used to fit the adjustable parameters of the Peng–Robinson equation of state (PR-EoS) and the calculated results are compatible with the experimental data. The PR-EoS calculates a decrease in the AOP and an increase in the BP as temperature rises. PR-EoS correctly predicts the qualitative effect of gas injection on the studied properties: all evaluated properties increase as CO2 is injected in the recombined oil.

CO2 effective conversion in Fe-C-Al-Si molten steel under vacuum conditions

The utilisation of CO2 in the vacuum refining process was proposed recently. To guide and predict the effects of CO2 blowing into the refining furnace, the reactions of CO2 with C, Al, and Si were analysed thermodynamically, and the CO2 effective conversion was defined to reflect the stirring effect of CO2 injection on molten steel. FactSage 7.1 software was employed to study the process of CO2 reacting with Fe-C-Al-Si liquid metal, where the reaction system involved elements and exhaust gas under different initial C contents in molten steel. Industrial trials were conducted with a Ruhrstahl-Heraeus refining process. The results show that the content of Si and O in Fe-C-Al-Si molten steel does not change much with CO2 injection under 2000 Pa and 1873 K. However, there is marked selective oxidation of C and Al by CO2. Further analysis shows that the reaction between Al and CO to generate C occurs when the initial C content is low enough. Higher CEC can be achieved through the selection of suitable steel grades and control of composition of the liquid steel. It is expected that this will enhance the stirring effect by CO2. Finally, lower vacuum pressure can promote CEC.

Influence of supercritical CO2-water on the micromechanical properties of sandstone

The effects of CO2-brine-rock interaction on the physical and macro-mechanical properties of rock have been extensively studied in CO2 sequestration-related research. However, there are few studies focus on mechanochemical effects of the interaction of supercritical CO2 (SC−CO2), water, and rock and its effects on micromechanical properties of sandstone. In this work, we studied the micromechanical mechanism of crack initiation induced by SC−CO2-water saturated sandstone. A micromechanical model including parameters of fracture cohesive strength, friction coefficient, and fracture energy was proposed, which extended the “sliding surface” to include not only the friction, but also the cohesions on the surfaces and the tensile resistance at the crack-tips. To this end, tests of two saturation conditions, water and SC−CO2-water, were conducted on 25 mm diameter by 50 mm length Sichuan sandstone with a porosity of ∼15.57 % for 15 days and 30 days under temperature of 80 ℃ and pressure of 30 MPa. Afterward, samples were subjected to triaxial compression tests with confining pressure up to 24 MPa. The mineralogical alteration and induced crack morphology were examined to better understand the mechanism of mechanochemical coupling on compression failure induced by SC−CO2-water-rock interaction. Experimentally, mineralogical and microstructural changes induced by illite and kaolinite dissolution, weaken the quartz grain contacts in SC−CO2-water saturated sandstone. Compared to water-saturated sandstone, the SC−CO2-water saturated sandstone exhibits a maximum reduction by 18.82 % and 21.21 % in compressive strength and crack initiation stress respectively under unconfined condition. Additionally, reductions of 5%, 50 %, and 37.3 % were observed in friction coefficient, fracture energy, and cohesive strength respectively for SC−CO2-water saturated sandstone. The reductions of these three parameters, especially the fracture energy and cohesive strength, significantly weaken SC−CO2-water saturated sandstone. The results are representative for the partly saturated zone where SC−CO2 is displacing the in-situ pore fluid and could be used to analyze effects of CO2 injection on stability and integrity of storage formation under mechanochemical coupling effects of SC−CO2-water on sandstone.

Alterations of asphaltenes chemical structure due to carbon dioxide injection

Asphaltenes precipitation during carbon dioxide injection to enhance recovery has been considered as one of the major challenges in the tertiary production phase. The effects of CO2 injection on asphaltenes chemical structure and stability in the matrix has not been fully understood yet. The present study aims to characterize asphaltenes structural alterations in the presence of CO2 at high temperature and pressure and then elaborates the mechanism in which these changes affect asphaltenes stability in the matrix. The chemical structure of four precipitated asphaltenes in the presence and absence of CO2 were characterized and compared. These results were coupled with the results of the stability assessment to determine the effects of structural alteration on asphaltenes stability in crude oil. Infrared (IR) spectroscopy results demonstrated the formation of amide functional group upon CO2 injection to the model oil. The precursor of such an observation is characterized to be the reaction of CO2 with amine functional group of the asphaltenes sample. Such a reaction led to the decrease of asphaltenes stability in the model oil sample. The results of the present study suggest that asphaltenes can be destabilized in the oil matrix through both chemical reactions and physical interactions. The presence of chemical functional groups that can react with CO2 in the reservoir conditions is the primary trigger to initiate asphaltenes destabilization. These findings can be used to further research asphaltenes disturbing mechanisms at the molecular level and scale them up to understand asphaltenes physical behaviors during CO2 injection.

Influence of CO2 injection on the pore size distribution and petrophysical properties of tight sandstone cores using nuclear magnetic resonance

AbstractCO2 injection has been proposed as an efficient method for enhanced oil recovery in low‐permeability sandstone reservoirs. When CO2 is injected into such reservoirs, the petrophysical properties as well as the pore size distribution of tight formation can be altered due to the interactions between CO2, water, and rock minerals. In this work, CO2 is introduced into the water‐saturated sandstone cores; nuclear magnetic resonance technique is then applied to obtain T2 spectrum of the sandstone cores before and after CO2 injection. The effect of CO2 injection on the pore size distribution is analyzed by comparing the obtained T2 spectrum. In addition, the change of petrophysical properties, that is, total porosity, porosity of the movable fluid, and permeability, are also discussed in this work. Test results show that after introducing CO2, the total volume of small pores is significantly increased. On the contrary, the total volume of medium pores decreases. In addition, the immovable fluid porosity increases in the small pores, while it decreases in the medium pores after injecting CO2. Based on the composition analysis, the concentration of the ions of Na+, K+, Ca2+, and Mg2+ increases in the produced fluid due to the interactions between CO2 and albite, and potash feldspar. After CO2 injection, the total porosity, movable fluid porosity, and permeability of these tight cores are significantly improved. This study is expected to be significant for understanding the mechanisms of alterations of petrophysical properties and pore size distribution of tight sandstone cores due to the CO2 flooding.

Effect of CO2 injection on interfacial tension of oil-formation water system under high temperature and pressure

The interfacial interaction between CO2 and oil and water is one of the important factors affecting the effect of CO2 enhanced oil recovery. Taking dead oil in Zhoucheng Oilfield as an example, the variation of interfacial tension between crude oil-carbonated water two-phase system and oil-formation water two-phase system was studied by pendant drop method. The influence of different CO2 saturation on the equilibrium interfacial tension of oil-formation water system and changes of equilibrium interfacial tension between crude oil-carbonated water system and crude oil-formation water system were analyzed. Moreover, previous studies did not reflect the experimental phenomena of extracting light hydrocarbons from oil droplets by CO2 through gas-water interface. This paper provides experimental research and analysis for this experimental phenomenon. The results show that the equilibrium interfacial tension of crude oil-carbonated water system decreases with the increase of pressure, and the dissolution and diffusion of the system becomes more and more obvious with the increase of pressure. The medium exchange occurs between oil and carbonated water, and the phenomenon of partial miscibility occurs. There is a threshold pressure value between crude oil and formation water with different CO2 saturation. Each group of samples has its threshold pressure and optimum CO2 injection rate. It’s not that the more CO2 injection, the better oil displacement effect. This research provides a reference for us to save the cost of CO2 flooding.

A simulation study on the effect of CO2 injection on the performance of the GTL process

This study enhances the efficiency of the Fischer-Tropsch process through CO2 injection. Syngas production in the reforming units is simulated for three cases; two cases for auto-thermal reforming (ATR) with varying steam flow rates and a case for steam-methane reforming (SMR). Outcomes demonstrate an enhancement in the total refined production and the optimisation of the growth probability (α) in the Anderson–Schulz–Flory (ASF) relationship and H2:CO proportion. Aspen HYSYS simulation outputs indicate that the ATR reformer at a steam flow rate 3223 T/D and a CO2 flow rate 1500 T/D represents an optimal scenario for product enhancement. Furthermore, a techno-economic analysis indicates that the ATR (C3) option is the best performing economically with a net profit per input of natural gas and refined product output generating 542.94 ($/T) and 722.74 ($/T) respectively. The environmental analysis demonstrates lowest carbon emissions with 1.76 and 2.34 kg CO2-e/T.

Evaluation of Multicomponent Adsorption Kinetics for Carbon Dioxide Enhanced Gas Recovery from Tight Shales

SummaryOnly 3 to 10% of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale-gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for carbon dioxide (CO2) than methane (CH4), which opens possibilities for carbon storage and new production strategies.This paper presents a new multicomponent adsorption isotherm that is coupled with a flow model for the evaluation of injection/production scenarios. The isotherm is dependent on the assumption that different gas species compete to adsorb on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles, this finite surface area is filled with species taking different amounts of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus Shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas-in-place reserves, recovery factors (RFs), and enhanced gas-recovery (EGR) potential according to the contributions from free-gas and adsorbed-gas components. The isotherm is further coupled with a dynamic flow model with application to CO2/CH4 substitution for CO2-ESGR, assuming only a gas phase exists in the system. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection/production setting representative of laboratory and field implementation and compare that with regular pressure depletion.The production scenario we consider is a 1D shale-core or matrix system first saturated with free and adsorbed CH4 gas with only the left-side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to an increase in pressure, where CO2 is preferentially adsorbed over CH4. The injected CO2 displaces but also mixes with the in-situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel farther into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism because the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is because CO2 takes approximately 24 times less space per mole than CH4.

Evolution of poroviscoelastic properties of silica-rich rock after CO2 injection

Injection of CO2 into the subsurface requires consideration of the poromechanical behavior of reservoir rock saturated with aqueous fluid. The material response is usually assumed to be elastic, to avoid consideration of induced seismicity, or viscoelastic, if long-term deformations are needed to be taken into the account. Both elastic and viscous behavior may be influenced by the chemical reactions that are caused by the acidic mixture formed as high-pressure CO2 enters the pore space saturated with aqueous fluid. In this study, we conduct laboratory experiments on a fluid-saturated porous rock - Berea sandstone, and evaluate its poromechanical properties. Subsequently, the specimens are treated with liquid CO2 for 21 days and the corresponding variations in their properties are determined. The constitutive model considering the elastic time-dependent behavior of porous rock is validated by comparing the measured and predicted specimen deformation. Presented data indicate that the effect of CO2 injection on the long-term response is more significant compared to the short-term response. It is suggested for the constitutive models that predict long-term reservoir behavior during CO2 storage to include not only the poroelastic response and its change due to treatment, but also the time-dependent deformation and its evolution caused by the changes in chemistry of the pore fluid.

A pore level study of syngas production in two-layer burner formed by staggered arrangement of particles

A 2D model of simplified porous burner is developed to analyze the syngas production from fuel-rich CO2/CH4 partial oxidation with detailed chemical kinetics GRI-Mech 1.2. The geometry simulates a two-layer burner, which is composed of 2.5 mm particles in the upstream and 7.5 mm particles in the downstream. A 2D packed bed of connected particles with staggered arrangement is developed. The discrete ordinates (DO) model is used to compute the surface to surface radiation and gas radiation. The solid conduction between the neighboring particles is taken into account by bridge approach. The predicted results are compared with experiment and good agreement between the predictions and experiment is observed. The effect of CO2 injection in the system is examined. It is demonstrated that 2D pore level simulations by simplified geometry with detailed chemical kinetics can capture the features of syngas compositions and temperature profiles. Local information of species, temperature and velocity distributions within pores in the burner is presented and analyzed. Results show that thermal nonequilibrium in the same particles exists in the entire burner, and that chemical nonequilibrium for the main syngas of H2, CO and CO2 is observed from exothermic zone to the burner outlet.

Effect of CO2 injection on adsorption of methane on shale from the Sichuan Basin in China

In order to understand the change of adsorption capacity of methane (CH4) after carbon dioxide (CO2) injection into shale at high pressure condition. The pore structure character and adsorption capacity of CH4 were analysed via low-pressure N2 adsorption and isothermal adsorption measurements for original and supercritical CO2 (ScCO2) treated shale samples from Jiaoshiba area in the Sichuan Basin. The results show that the ScCO2 treated samples have lower specific surface areas, less micropore and mesopore, and more macropore compare to original one. For ScCO2 treated shale samples, specific surface area and micropore decrease with increasing temperature. Furthermore, the absolute adsorption capacity of CH4 in original shale is higher than that in ScCO2 treated ones, indicating that micropore specific surface area is probably the main factor controlling adsorption capacity of CH4 on shale. For all samples, the absolute adsorption capacity of CH4 increase with increasing pressure from 0 MPa to 43 MPa and then tended to be stable.

Experimental investigation of effects of CO2 injection on enhanced methane recovery in coal seam reservoirs

Enhanced coalbed methane (ECBM) recovery performed by injecting CO2 into coal reservoirs has been found to be a viable option for methane recovery, while CO2 injection into coal seams, especially unmineable ones, has great potential to sequestrate large volumes of CO2 to mitigate greenhouse gas accumulation in the atmosphere. This study was therefore initiated to investigate the effect of CO2 flooding on ECBM recovery and CO2 storage in coal. A series of CO2 core flooding tests was carried out on a high rank bituminous coal core with CO2 injection pressures from 6 to 10 MPa. CO2 injection rate, methane and CO2 production rates, methane displacement efficiency and the volumetric strains of the core were calculated and recorded to enable interpretation of the results. It was observed that, compared with natural methane production in which only around 51.73% of methane is recovered, CO2 injection provides excellent methane displacement efficiency (over 90%), especially for high injection pressures (greater than 8 MPa), which drive methane completely out of the coal sample. Although higher CO2 flooding pressure favours greater CO2 injection rates and methane production rates for any coal types, high rank coal shows faster and greater methane production and CO2 storage capacity. The observed rapid breakthrough of CO2 in the gas produced by elevated CO2 injection, especially for high injection pressures, may complicate the gas separation process. Adsorption-induced volumetric strain is approximately proportional to the CO2 storage capacity in coal which increases with CO2 pressure, and the strain reduces coal permeability and therefore CO2 injectivity and methane production.

BIO_ALGAE 2: improved model of microalgae and bacteria consortia for wastewater treatment.

A new set up of the integral mechanistic BIO_ALGAE model that describes the complex interactions in mixed algal-bacterial systems was developed to overcome some restrictions of the model. BIO_ALGAE 2 includes new sub-models that take into account the variation of microalgae and bacteria performance as a function of culture conditions prevailing in microalgae cultures (pH, temperature, dissolved oxygen) over daily and seasonal cycles and the implementation of on-demand dioxide carbon injection for pH control. Moreover, another aim of this work was to study a correlation between the mass transfer coefficient and the hydrodynamics of reactor. The model was calibrated using real data from a laboratory reactor fed with real wastewater. Moreover, the model was used to simulate daily variations of different components in the pond (dissolved oxygen, pH, and CO2 injection) and to predict microalgae (XALG) and bacteria (XH) proportions and to estimate daily biomass production (Cb). The effect of CO2 injection and the influence of wastewater composition on treatment performance were investigated through practical study cases. XALG decreased by 38%, and XH increased by 35% with respect to the system under pH control while microalgae and bacteria proportions are completely different as a function of influent wastewater composition. Model simulations have indicated that Cb production (~ 100gTSSm-3day-1 for manure and centrate) resulted lower than Cb production obtained using primary influent wastewater (155gTSSm-3day-1).