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The most widely used process for hydrogen production is steam methane reforming. It can be carried out using a membrane reactor in which simultaneous hydrogen production and purification occur. Mathematical modeling of these reactors plays a key role in the selection of the design and operating parameters that yield high performance for the reactor. This review study discusses, synthesizes, and compares different mathematical modeling studies on the packed bed membrane reactors for hydrogen production from methane found in the literature. Different approaches used in these modeling studies for the hydrogen permeation steps, reaction kinetic expressions, phases involved (pseudo-homogeneous and heterogeneous), and spatial dimensions (one, two, and three dimensional) are given.

Screening tests of a number of amines and organic diluents indicated that 30% weight blends of 2-(methylamino)ethanol (MMEA) or 2-(ethylamino)ethanol (EMEA) with bis(2-ethoxyethyl) ether (DEGDEE) split into two liquid phases upon CO2 capture, an upper CO2 lean phase (mainly DEGDEE) and a lower CO2 enriched phase (mainly amine carbamate and protonated amine). These water-free biphasic absorbents have experimental CO2 loading capacity in the range 0.52-0.54. Besides batch experiments to measure the efficiency of CO2 capture and absorbent regeneration, the biphasic absorbents were tested in continuous cycles of CO2 (15% v/v in air) absorption-desorption carried out in packed columns. CO2 capture efficiency up to 97.6% was achieved with EMEA-DEGDEE and desorption temperature of the sole EMEA carbamate at 110 °C. 13C NMR analysis was used to identify and quantify the species occurring in the different liquid phases. The features of the absorbent were compared to those of 30% weight aqueous MEA. The better performances of our absorbent were greater absorption efficiency, reduced flow rate in the desorber and avoidance of any parasitic diluent to be heated in the desorption step.

The first dynamic modeling study of CO2 geological storage in the Baltic Sea basin is presented. The focus has been on the southern part of the Dalders Monocline. The objective is to get order-of-magnitude estimates of the behavior of the formations during potential industrial scale CO2 injection and subsequent storage periods, with an emphasis on two important aspects of CO2 storage: the injection-induced pressure impact and the long-term upslope migration. In order to maximize the confidence in the model predictions, this work employs a set of different modeling approaches of varying complexity, including a semi-analytical model, a sharp-interface vertical equilibrium (VE) model and a TOUGH2-ECO2N model. The semi-analytical model provides fast estimation of the pressure buildup as well as its sensitivity to variation of the reservoir parameters. Given a certain pressure threshold, a maximum injection rate is estimated from the semi-analytical model and is then fed to the numerical models. The pressure buildup predicted by the numerical models fall close to that by the semi-analytical solution. Extensive modeling of the post-injection upslope migration and trapping evolution together with sensitivity analysis suggests that it is unlikely for CO2 to leak through the north end of the formation. Under the currently considered scenario, the dominant constraint for the storage capacity is the pressure buildup. The pressure limited capacity (Cp) of the southern Dalders Monocline for the scenario studied here is estimated to be about 100 Mt for a 50-year injection duration. Cp is found to increase with permeability as Cp ∼ k0.926. Given the knowledge of the dominant constraint for capacity, storage optimization can be specifically targeted on the injectivity issue and operational strategies can be designed to relieve the pressure buildup (e.g., by adding brine production wells, using horizontal wells).

This paper introduces a generalized formulation for the entropy production analysis. The use of relations valid under the hypothesis of validity of the principle of detailed balance, that is violated in the remarkable case of irreversible reactions, is avoided by using more general expressions for the entropy generation due to the chemical reactions. As a result, the new formulation is applicable to generate reduced mechanisms involving both irreversible reactions or ad hoc estimated reverse rates.

The separation of biogas leads to not only recovery and sequestration of CO2, but also to much greater purification and recovery of value-added CH4 able to be used, for example, to directly feed pipelines for domestic or small plants. In this work, an alternative approach for a preliminary design of separation process based on the use of polymeric membranes is proposed. Two different types of polymeric membranes were taken into account, Hyflon AD60 and Matrimid 5218, the first showing a higher permeability with respect to other membranes but a quite low selectivity (12.9), the second exhibiting a higher selectivity with respect to other membranes (41 and 100) even though a lower permeability. Four possible operation schemes using two different types of membranes in multistage configuration system are analysed as functions of the main design parameters, i.e., pressure ratio and permeation number. The achieved results are compared with certain targets and are also discussed in terms of process metrics, according to the Process Intensification strategy. This latter analysis, coupled with a conventional one, provides an alternative point of view over the evaluation of the plant performance taking into account not only the final characteristics of the streams but also process efficiency, exploitation of raw material and energy, and the footprint occupied by the installation.

This research provides new techno-economic insights into integrating flexible combined-cycle gas turbines with post-combustion carbon capture and storage (CCGT-CCS) for low-carbon power systems. This study developed a versatile unit-commitment optimisation model of CCGT-CCS. This research highlights the model’s adaptability, accommodating diverse techno-economic configurations, feed gases (e.g., biomethane or fossil natural gas), carbon capture rates, and policy instruments. This generalisation empowers seamless application in various policy and market contexts, making the model a potent tool for researchers and policymakers. While the case study focuses on the UK, the findings are relevant for most low-carbon power systems with variable renewable supplies. Analysing the UK’s net-zero scenarios from 2030 to 2050, the economic viability of flexible CCGT-CCS was highlighted. Intertemporal flexibility proves highly valuable with greater electricity price volatility, with a total ROI range of 81–246 %, surpassing the CCGT-CCS plant’s ROI (7–64 %). A flexible solvent storage solution should be seen in the context of the overall system ‘flexibility’ requirements of a low-carbon power system. On a cost basis, solvent storage represents just a fraction of the capital costs of more “mainstream” energy storage technologies, such as lithium-ion batteries or hydro-pumped storage, while CCGT-CCS offers firm power. Overall, while seen as a rather technical solution, if abated fossil fuel generation is to be part of a future low-carbon power system, having this flexibility adds economic benefits not just to operators but also improves overall system security and complements high shares of variable renewables on the grid.

Abstract Many simulation studies on CO2 storage in deep saline aquifers focus on flow transport modelling and pressure development. Studies including geochemical aspects mostly address the acidic impact of pure CO2 injection on the minerals of the reservoir complex. More recent reactive transport simulations respect compositions of a flue gas stream closer to reality, i.e. they include physical or geochemical impacts of impurities within the CO2 stream. Here the common approach is to introduce trace gases into the multidimensional system as dissolved solutes in an additional aquatic phase, injected into the reservoir as brine. The most recent release of version V3.0-OMP of the TOUGHREACT code provides the new feature “Transport of trace gas species in CO2–H2O carrier gas”, allowing for direct injection and transport of trace gases in the CO2 phase. This study addresses the geochemical impact of co-injected SO2 as a CO2 flue gas impurity on the reservoir rock in a generic model, based on parameters of the Heletz saline aquifer. Therefore numerical 2D reactive transport simulations applying the trace gas transport approach as provided by TOUGHREACT V3.0 are performed for a ten year injection period. The simulations predict a distinct inner region of 200 m radial distance under the dominating impact of dissolved SO2, while a distance of up to 2000 m is influenced by CO2. The region impacted by SO2 is characterised by a distinct ankerite dissolution and coupled precipitation pattern of anhydrite. In the analysis of the results, special emphasis is given to the benefits and restrictions of the trace gas transport approach in comparison to the impurity modelling by injection of additional brine, particularly addressing the topic of ionic strength limitations.

Abstract In order to evaluate chemical impacts of SO2 impurity on reservoir rock during CO2 capture and storage in deep saline aquifers, several batch reactor experiments were performed on laboratory scale using core rock samples from the pilot CO2 injection site in Heletz. In this experiment, the samples were exposed to pure N2(g), pure CO2(g), and CO2(g) with an impurity of 1.5% SO2(g) under reservoir conditions for pressure and temperature (14.5 MPa, 60 °C). Based on the set-up and the obtained experimental results, a batch chemical model was established using the numerical simulation program TOUGHREACT V3.0-OMP. Comparing laboratory and simulation data provides a better understanding of the rock-brine-gas interactions. In addition, it offers an evaluation of the capability of the model to predict chemical interactions in the target injection reservoir during exposure to pure and impure CO2. The best match between the geochemical model and experimental data was achieved when the reactive surface area of minerals in the model was adjusted in order to calibrate the kinetic rates of minerals. The simulations indicated that SO2(g) tends to dissolve rather quickly and oxidizes under a kinetic control. Hence, it has a stronger effect on the acidity of the brine than pure CO2(g) and as a result, increased mineral dissolution and caused the precipitation of sulfate and sulfide minerals. Ankerite, dolomite, and siderite, the most abundant carbonates in the sandstone rock sample, are subject to stronger dissolution in the presence of SO2 gas. The performed simulations confirmed a slower dissolution rate for ankerite and siderite than for dolomite. The model reproduced the precipitation of pyrite and anhydrite as observed in the laboratory. The dissolution of dolomite observed in the batch reaction test with pure N2 is assumed to be due to slight contamination with oxygen and modelling supported this. The inclusion of SO2 increased the porosity over that of the pure CO2 case, and is thus considered to increase the permeability and injectivity of the reservoir as well. Exposure to SO2 also increased the concentration of trace elements. The calibrated kinetic parameters determined in this study will be used to model the injection and long-term behavior of CO2 at the Heletz field site, and may be used for similar geologic reservoirs.

Industrial CO2 emissions to the atmosphere can be reduced through geological storage, where the gas is injected into the subsurface and trapped by several mechanisms. Residual and solubility trappi ...