This research investigates the feasibility of magnetic ion exchange (MIEX) resin as the adsorbent for the removal of chlorite through a laboratory study using batch adsorption experiments. The agitation speed of 100 rpm is the optimum agitation intensity. The removal efficiency of chlorite increases with increasing dosage of MIEX resin. The optimum pH is 5–7. The coexisting anions and natural organic matter reduce the removal efficiency of chlorite. The kinetic process at the low chlorite concentration (1.02 mg/L) is highly possible to be pseudo-first-order. However, the pseudo-second-order model can fit the kinetic data quite well at higher chlorite concentrations (2.28–5.57 mg/L). At the initial stage of adsorption, the intra-particle diffusion is the rate-limiting step, but the adsorption rate is controlled by the film diffusion and the intra-particle diffusion after 10 min. The adsorption equilibrium can be approximately attained within 40 min, and Redlich–Peterson isotherm model fits best to the equilibrium data. The adsorption is a thermodynamically feasible, spontaneous, and endothermic ion-exchange process. The removal of chloride on MIEX resin is an ion-exchange mechanism. Dissolved organic carbon can be removed effectively as well as chlorite and chlorate using MIEX resin in real water. Therefore, MIEX resin is a promising technology for the removal of chlorite from aqueous solution. @en

Although flow through fractured rocks involves many different length-scales, it is crucial for the prediction of continuum-scale single- and multi-phase flow functions to understand, at the pore-scale, the interaction between the rock matrix and fractures. Here we present a pore-network extraction method in which the pore diameters and fracture apertures are of similar size. The method involves a shrinking algorithm to extract a hybrid skeleton of medial axes and surfaces, and it includes a workflow to convert the medial surfaces of fractures into dense networks of virtual medial axes, allowing generation of an integrated pore-network for the entire pore space. Appropriate single- and two-phase flow properties are assigned to network elements representing the fractures. We validate the method via comparisons between pore network flow simulations and an analytical solution, direct flow simulations and experimental observations. The network calculations are several orders of magnitude faster than the direct simulations.@en

In 2006, China published the first National Evaluation Standard for Green Building (ESGB), which soon became the most widely spread evaluation system in the country. With the fast growth of urbanization, ESGB 2006 version no longer meets the current needs and requires an update. Based on the implementation outcomes of ESGB 2006 and expert opinions, the Ministry of Housing and Urban-rural Development published a new version of ESGB in 2014 (ESGB 2014). This research reviews the previous cases of buildings accredited with ESGB 2006 and collects the facts and data to explain the implementation results and identifies its weakness of the ESGB 2006. A comparative analysis of the ESGB 2014 with ESGB 2006 is based on an in-depth overview of both ESGB 2014 and ESGB 2006. The comparison results shows the improvement of the current ESGB 2014 in details, i.e., evaluated object, stage partition, weighted value, structure, indicators, etc. A case study is followed by choosing one building project to evaluate and calculate the green building accreditation according to both ESGB 2014 and ESGB 2006, and demonstrate the differences and development of ESGB 2014.@en

Fractured reservoirs contain around 60% of the world's remaining oil reserves. Fracture corridors have been noticed as a major architectural element in outcrops of fractured rock and are known to affect recovery by providing high-permeability flow conduits. Simulations of fractured reservoirs using multi-porosity and multi-permeability models has proven to be challenging, with ever-changing modifications being proposed since the introduction of the dual porosity model in the 1960s. To increase the reliability of reservoir simulation of fractured reservoirs, we propose a new workflow to represent fractured reservoirs by coupling Discrete Fracture and Matrix (DFM) models for fracture corridor properties (which uses finite element and finite volume methods), and the conventional single porosity simulation(which uses finite difference methods). Relative permeabilities of fracture corridors are upscaled over a single grid block size using DFM models based on an unstructured mesh that accommodates fracture corridor patterns and characteristics. The upscaled relative permeabilities are transferred into a single porosity simulation model to reproduce the behaviour of fractured reservoirs without resorting to the transfer functions. Various fracture patterns and apertures were studied to investigate their impact on flow properties. Also, different multiphase upscaling techniques were investigated based on the dominant driving forces and the type of boundary conditions used in the upscaling process. A performance match was done between two models, a fine-mesh DFM model and a simple coarse single porosity model that uses the upscaled relative permeabilities. The models behaved similarly. Recommendations are derived as to how to use appropriate upscaling methods. The new workflow complements and may even have the potential to eliminate the need for classical dual-porosity models.@en

Carbonate reservoirs have textural heterogeneities at all length-scales (triple porosity pore-vug-fracture) and tend to be mixed- to oil-wet The choice of an enhanced oil recovery process and the prediction of oil recovery require a sound understanding of the fundamental controls on fluid flow in mixed- to oil-wet carbonate rocks, as well as physically robust flow functions, i e relative permeability and capillary pressure functions Obtaining these flow functions is a challenging task, especially when three fluid phases coexist, such as during water-alternating-gas injection (WAG) We have recently developed a method for integration of pore-networks derived from micro CT images at different length-scales, thus capturing pore structures from different types of porosity The network integration method honours the connectivity between different pore types, including micro-fractures, and their spatial distribution In this work, we use these multi-scale networks as input for our three-phase flow pore-network model, which comprises a novel thermodynamic criterion for formation and collapse of oil layers that strongly depends on the fluid spreading behaviour and the rock wettability The criterion affects in particular the oil relative permeability at low oil saturations and the accurate prediction of residual oil saturations We generate three-phase flow functions for gas injection and WAG from networks with carbonate pore geometries and connectivities and we demonstrate the impact on residual saturations of the different types of porosity and the interaction with different realistic wettability scenarios We also show that the network generated three-phase flow relative permeabilities are distinctly different from traditional models, such as Stone's The flow functions will be used in a heterogeneous carbonate reservoir model and to demonstrate their impact on the sweep efficiency.@en