Chemical absorption using amine-based solvents have proven to be the most studied, as well as the most reliable and efficient technology for capturing carbon dioxide (CO₂) from exhaust gas streams and synthesis gas in all combustion and industrial processes. The application of single amine-based solvents especially the very reactive monoethanolamine (MEA) is associated with a parasitic energy demand for solvent regeneration. Since regeneration energy accounts for up to three-quarters of the plant operating cost, efforts in its reduction have prompted the idea of using blended amine solvents. This review paper highlights the success achieved in blending amine solvents and the recent and future technologies aimed at increasing the overall volumetric mass transfer coefficient, absorption rate, cyclic capacity and greatly minimizing both degradation and the energy for solvent regeneration. The importance of amine biodegradability (BOD) and low ecotoxicity as well as low amine volatility is also highlighted. Costs and energy penalty indices that influences the capital and operating costs of CO₂ capture process was also highlighted. A new experimental method for simultaneously estimating amine cost, degradation rate, regeneration energy and reclaiming energy is also proposed in this review paper.

Amines are well-known for their reversible reactions with CO₂, which make them ideal for CO₂ capture from several gas streams, including flue gas. In this respect, selective CO₂ absorption by aqueous alkanolamines is the most mature technology but the process is energy intensive and has also corrosion problems. Both disadvantages can be diminished to a certain extent by chemical adsorption of CO₂ selectively. The most important element of the chemical adsorption of CO₂ involves the design and development of a suitable adsorbent which consist of a porous support onto which an amine is attached or immobilized. Such an adsorbent is often called as solid amine sorbent. This review covers solid amine-based studies which are developed and published in recent years. First, the review examines several different types of porous support materials, namely, three mesoporous silica (MCM-41, SBA-15 and KIT-6) and two polymeric supports (PMMA and PS) for CO₂ adsorption. Emphasis is given to the synthesis, modifications and characterizations -such as BET and PXRD data-of them. Amination of these supports to obtain a solid amine sorbent through impregnation or grafting is reviewed comparatively. Focus is given to the adsorption mechanisms, material characteristics, and synthesis methods which are discussed in detail. Significant amount of original data are also presented which makes this review unique. Finally, relevant CO₂ adsorption (or equilibrium) capacity data, and cyclic adsorption/desorption performance and stability of important classes of solid amine sorbents are critically reviewed. These include severa PEI or TEPA impregnated adsorbents and APTES-grafted systems.

Carbon dioxide (CO₂) is an influential greenhouse gas that has a significant impact on global warming partly. Nowadays, many techniques are available to control and remove CO₂ in different chemical processes. Since the spray dryer has high removal efficiency rate, a laboratory-scale spray dryer is used to absorb carbon dioxide from air in aqueous solution of NaOH. In the present study, the impact of NaOH concentration, operating temperature and nozzle diameter on removal efficiency of CO₂ is explored through experimental study. Moreover, the reaction kinetic of NaOH with CO₂ is studied over the temperature range of 50-100 °C in a laboratory-scale spray dryer absorber. In the present contribution, a simple reaction rate equation is proposed that shows the lowest deviation from the experimental data with error less than 2%.

This paper presents the application of a neural network rule extraction algorithm, called the piece-wise linear artificial neural network or PWL-ANN algorithm, on a carbon capture process system dataset. The objective of the application is to enhance understanding of the intricate relationships among the key process parameters. The algorithm extracts rules in the form of multiple linear regression equations by approximating the sigmoid activation functions of the hidden neurons in an artificial neural network (ANN). The PWL-ANN algorithm overcomes the weaknesses of the statistical regression approach, in which accuracies of the generated predictive models are often not satisfactory, and the opaqueness of the ANN models. The results show that the generated PWL-ANN models have accuracies that are as high as the originally trained ANN models of the four datasets of the carbon capture process system. An analysis of the extracted rules and the magnitude of the coefficients in the equations revealed that the three most significant parameters of the CO₂ production rate are the steam flow rate through reboiler, reboiler pressure, and the CO₂ concentration in the flue gas.

CO₂ flooding is one of the most promising techniques to enhance both light and heavy oil recovery. In light oil recovery, the production pressure in CO₂ flooding in general keeps constant in order to maintain the miscibility of injected CO₂ and crude oil; while in heavy oil recovery, a depleting pressure scheme may be able to induce foamy oil flow, thus the oil recovery could be further enhanced. In this study, different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO₂ flooding strategies.

For the core-flooding experiments, 1500 mD sandstone cores, formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition (55 °C and 11 MPa) were used. Before each CO₂ flooding test, early stage water-flooding was conducted until the water cut reached 90%. Different CO₂ injection rates and production pressure control strategies were tested through core-flooding experiments. Experimental results indicated that a slower CO₂ injection rate (2 ml/min) led to a higher recovery factor from 31.1% to 36.7%, compared with a high CO₂ injection rate of 7 ml/min; for the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%; while a pressure depletion with 47.2 kPa/min at the production port yielded 7% more oil recovery; and the best pressure control scheme in which the production pressure keeping constant during CO₂ injection period, then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5% of the initial OOIP.

For the numerical simulations study, the same oil relative permeability curve was applied to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes are different. A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes. Through this study, it is suggested that the pressure control scheme can be optimized in order to maximize the CO₂ injection performance for enhanced heavy oil recovery.

The effective development of unconventional tight oil formations, such as Bakken, could include CO₂ enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO₂. It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil-injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO₂, CO₂-enriched flue gas, natural gas, nitrogen, and CO₂-enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO₂ outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil-CO₂ MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO₂ had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil-pure CO₂ MMP and effect of impurities in the gas phase on MMP change. The Bakken oil-CO₂ had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N₂, can increase MMP significantly.

This paper presents the effectiveness of the CO₂ injection process at different periods during gas-condensate reservoir development. Taking a real gas-condensate reservoir located in China's east region as an example, first, we conducted experiments of constant composition expansion (CCE), constant volume depletion (CVD), saturation pressure determination, and single flash. Next, a series of water/CO₂ flooding experiments were been investigated, including water flooding at present pressure 15 MPa, CO₂ flooding at 25.53 MPa, 15 MPa, which repents initial pressure and present pressure respectively. Finally, the core flooding numerical model was constructed using a generalized equation-of-state model reservoir simulator (GEM) to reveal miscible flooding mechanism and the seepage flow characteristics in the condensate gas reservoir with CO₂ injection. A desirable agreement achieved in experimental results and predicted pressure volume temperature (PVT) properties by the modified equation of state (EOS) in the CVD and CCE tests indicated that the proposed recombination method can successfully produce a fluid with the same phase behavior of initial reservoir fluid with an acceptable accuracy. The modeling results confirm the experimental results, and both methods indicate that significant productivity loss can occur in retrograde gas condensate reservoirs when the flowing bottom-hole pressure falls below dew point pressure. Moreover, the results show that CO₂ treatment can improve gas productivity by a factor of about 1.39 compared with the water flooding mode. These results may help reservoir engineers and specialists to restore the lost productivity of gas condensate.

Carbon capture and storage in deep geological formations is a method to reduce greenhouse gas emissions. Supercritical CO₂ is injected into a reservoir and dissolves in the brine. Under the impact of pressure and temperature (P-T) the aqueous species of the CO₂-acidified brine diffuse through the cap rock where they trigger CO₂-water-rock interactions. These geochemical reactions result in mineral dissolution and precipitation along the CO₂ migration path and are responsible for a change in porosity and therefore for the sealing capacity of the cap rock. This study focuses on the diffusive mass transport of CO₂ along a gradient of decreasing P-T conditions. The process is retraced with a one-dimensional hydrogeochemical reactive mass transport model. The semi-generic hydrogeochemical model is based on chemical equilibrium thermodynamics. Based on a broad variety of scenarios, including different initial mineralogical, chemical and physical parameters, the hydrogeochemical parameters that are most sensitive for safe long-term CO₂ storage are identified. The results demonstrate that P-T conditions have the strongest effect on the change in porosity and the effect of both is stronger at high P-T conditions because the solubility of the mineral phases involved depends on P-T conditions. Furthermore, modeling results indicate that the change in porosity depends strongly on the initial mineralogical composition of the reservoir and cap rock as well as on the brine compositions. Nevertheless, a wide range of conditions for safe CO₂ storage is identified.

Carbon dioxide capture, utilization and storage (CCUS) -including conversion to valuable chemicals-is a challenging contemporary issue having multi-facets. The prospect to utilize carbon dioxide (CO₂) as a feedstock for synthetic applications in chemical and fuel industries -through carboxylation and reduction reactions-is the subject of this review. Current statute of the heterogeneously catalyzed hydrogenation, as well as the photocatalytic and electrocatalytic activations of conversion of CO₂ to value-added chemicals is overviewed. Envisaging CO₂ as a viable alternative to natural gas and oil as carbon resource for the chemical supply chain, three stages of development; namely, (i) existing mature technologies (such as urea production), (ii) emerging technologies (such as formic acid or other single carbon (C1) chemicals manufacture) and (iii) innovative explorations (such as electrocatalytic ethylene production) have been identified and highlighted. A unique aspect of this review is the exploitations of reactions of CO₂ -which stems from existing petrochemical plants-with the commodity petrochemicals (such as, methanol, ethylene and ethylene oxide) produced at the same or nearby complex in order to obtain value-added products while contributing also to CO₂ fixation simultaneously. Exemplifying worldwide ethylene oxide facilities, it is recognized that they produce about 3 million tons of CO₂ annually. Such a CO₂ resource, which is already separated in pure form as a requirement of the process, should best be converted to a value-added chemical there avoiding current practice of discharging to the atmosphere.

The potential utilization of CO₂, captured at power plants, should also been taken into consideration for sustainability. This CO₂ source, which is potentially a raw material for the chemical industry, will be available at sufficient quality and at gigantic quantity upon realization of on-going tangible capture projects. Products resulting from carboxylation reactions are obvious conversions. In addition, provided that enough supply of energy from non-fossil resources, such as solar [1], is ensured, CO₂ reduction reactions can produce several valuable commodity chemicals including multi-carbon compounds, such as ethylene and acrylic acid, in addition to C1 chemicals and polymers. Presently, there are only few developing technologies which can find industrial applications. Therefore, there is a need for concerted research in order to assess the viability of these promising exploratory technologies rationally.

Recent studies have shown that the concentration of greenhouse gases such as carbon dioxide in the atmosphere is growing rapidly over recent years and this can lead to major dangers for the planet. This growth is mainly due to the emissions from fossil power source such as diesel plants and gas turbines. The purpose of the present paper is to study the feasibility of integrating a technique based on power to gas concept in fossil power plants such as gas turbine. This work is based on the reduction of pollutant gas emissions produced from a gas turbine plant, especially the carbon dioxide. This captured gas (CO2) can be converted once again into energy via the technique of power to gas concept. This concept starts by extracting CO₂ from exhaust gases which is carried out by multiple chemical process. On the other side, H2 is produced from water electrolysis using the excess electricity which is produced but not consumed by the existing loads. finally the production of Methane (CH4) can be achieved by combination of the captured CO₂ and the extracted H2 via a reactor known as a reactor of Sabatier, this operation is called methanation or hydrogenation of carbon dioxide. Simulation results are presented for the validation of the proposed technique based on real data obtained on site from a gas turbine plant.

Majority of geologic CO₂ storage sites for currently operated large-scale integrated carbon capture and storage projects (LSIPs) in operation around the world are depleted oil fields that have been undergone significant depletion and re-pressurization prior to injection of captured CO₂. A better understanding of any of the implications associated with past depletion and re-pressurization histories to “out of injection zone” migration of injected CO₂ can help in making monitoring strategies significantly more effective. Being the geologic CO₂ storage demonstration sites for two most active LSIPs in the US, the West Hastings and the Bell Creek Oil Fields are the main focus of present study.

The monitoring technologies that have been used/deployed/tested at both the normally pressured West Hastings and the subnormally pressured Bell Creek storage sites appear to adequately address any of the potential “out of zone migration” of injected CO₂ at these sites. It would be interesting to see if any of the collected monitoring data at the West Hastings and the Bell Creek storage sites could also be used in future to better understand the viability of initially subnormally pressured and subsequently depleted and re-pressurized oil fields as secure geologic CO₂ storage sites with relatively large storage CO₂ capacities compared to the depleted and re-pressurized oil fields that were initially discovered as normally pressured.

Depleted gas reservoirs are used for a large-scale carbon dioxide (CO₂) storage and reduction of the greenhouse gas released into the atmosphere. To identify a suitable depleted reservoir, it is essential to do a preliminary and comprehensive assessment of key storage factors such as storage capacity, injectivity, trapping mechanisms, and containment. However, there are a limited number of studies providing a preliminary assessment of CO₂ injectivity potential in depleted gas reservoirs prior to a CO₂ storage operation. The aim of this study is to provide a preliminary assessment of a gas field located in Malaysia for its storage potential based on subsurface characterization prior to injection. Evaluation of the reservoir interval based on the facies, cores, and wireline log data of a well located in the field indicated that the pore type and fabrics analysis is very beneficial to identify suitable locations for a successful storage practice. Although the results obtained are promising, it is recommended to combine this preliminary assessment with the fluid-mineral interactions analysis before making any judgment about reliability of storage sites.

This paper presents an algorithm that combines model predictive control (MPC) with MINLP optimization and demonstrates its application for coal-fired power plants retrofitted with solvent based post-combustion CO₂ capture (PCC) plant. The objective function of the optimization algorithm works at a primary level to maximize plant economic revenue while considering an optimal carbon capture profile. At a secondary level, the MPC algorithm is used to control the performance of the PCC plant. Two techno-economic scenarios based on fixed (capture rate is constant) and flexible (capture rate is variable) operation modes are developed using actual electricity prices (2011) with fixed carbon prices ($AUD 5, 25, 50/tonne-CO₂) for 24 h periods. Results show that fixed operation mode can bring about a ratio of net operating revenue deficit at an average of 6% against the superior flexible operation mode.

Carbon capture and sequestration technology is recognized as a successful approach taken to mitigate the amount of greenhouse gases released into the atmosphere. However, having a successful storage practice requires wise selection of suitable wells in depleted oil or gas fields to reduce the risk of leakage and contamination of subsurface resources. The aim of this paper is to present a guideline which can be followed to provide a better understanding of sophisticated wells chosen for injection and storage practices. Reviewing recent studies carried out on different aspects of geosequestration indicated that the fracture pressure of seals and borehole conditions such as cement-sheath integrity, distance from faults and fractures together with the depth of wells are important parameters, which should be part of the analysis for well selection in depleted reservoirs. A workflow was then designed covering these aspects and it was applied to a depleted gas field in Malaysia. The results obtained indicated that Well B in the field may have the potential of being a suitable conduit for injection. Although more studies are required to consider other aspects of well selections, it is recommended to employ the formation integrity analysis as part of the caprock assessment before making any decisions.