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Taking advantage of the analogy between hydraulic and electrical flows to facilitate the prediction of porous media characteristics is a longstanding practice in engineering and science applications. The relationships between hydraulic and electrical properties are widely used in the characterization of transport phenomena relying on the strong correlation between electric and hydraulic flow conductance. However, due to the lack of small-scale investigations the similarity among their pathways/tortuosities is still unclear. Here a series of direct finite element numerical simulations are conducted within pore-level microstructures to extract and compare the streamlines of both electric and fluid flow currents and examine the accuracy of the hydraulic-electric analogy by predicting the petrophysical characteristics of the case studies. The fluid flow and electric transports are simulated through low-porosity digital unconsolidated packings of polydispersed grains representing the Athabasca oil sands deposit as the second largest oil reserve in the world. The formation factor, porosity, and absolute permeability of the media under consideration are predicted, and consequently, the streamlines of both electric and hydraulic currents are extracted and compared in terms of length, shape, and pathways. According to the results, the fluid flow streamlines are longer and pose differently than the homogeneous electric current streamlines. The average ratio between the hydraulic and electric tortuosities is 1.15 and a local extremum occurs at the porosity of eighteen percent. Pedotransfer functions for tortuosities, dimensionless permeability, and formation factor are proposed underpinning the rigorous relationships between transport processes in porous media. [ABSTRACT FROM AUTHOR]

Aqueous based foam injection has gained interest for conventional oil recovery in recent times. Foam can control the mobility ratio and improve the sweep efficiency in oil reservoirs over gas flooding. However, due to the high viscosity of the oil, its application in heavy oil reservoirs is challenging. Moreover, the oil-wet nature of carbonate reservoirs makes it difficult for aqueous based foam to efficiently remove the heavy oil. On the other hand, hydrocarbon solvents have been used for decreasing the heavy oil viscosity and increase its recovery by diffusion and mixing mechanisms. However, the low rate of diffusion/dispersion, inadequate sweep efficiently and asphaltene precipitation, especially in heterogeneous reservoirs, are the major challenges during solvent injection. In this paper, hydrocarbon solvent based foam (SBF) as an alternative to solvent flooding is explored for heavy oil recovery from a fractured porous media. Hydrocarbon solvent-based CO 2 foam was used to increase sweep efficiency during heavy oil recovery. The foam was generated with the help of a fluorosurfactant in a hydrocarbon solvent. Static bulk performances of foam were analyzed at different concentrations of surfactant. Surface tension measurements were also performed to study the adsorption of surfactant into the liquid-gas interface and its effect on foamability and foam stability. A specially designed fractured micromodel (oil wet, representing fractured carbonate reservoirs) was used to visualize the pore-scale phenomena during solvent based foam injection. For the first time, extra heavy oil with a viscosity of about 30,000 cp has been used in this study for pore scale visualization. A high-quality camera was utilized to capture images/movies. According to static experiments, although the value of the surface tension of hydrocarbon solvent was initially low, the addition of surfactant slightly decreased the surface tension further improving the foam stability. However, the mechanisms involved in foamability and foam stability of non-aqueous based foam are more complicated than water based foam and cannot be discussed solely based on surface tension and bulk analysis. In addition, dynamic pore scale observation through this study revealed that solvent based foam can significantly contribute to heavy oil recovery with different mechanisms. At the initial stage, solvent diffuses and mixes with viscous oil and reduce the viscosity. Later, foam bubbles improve the sweep efficiency by diverting the solvent toward the untouched part of the porous media. Foam bubbles partially blocked the larger pores in matrix/swept-area increasing the contact of solvent and heavy oil, providing better mixing. Therefore, oil is swept much faster and more efficiently from the grain in oil-wet porous media compared to that of conventional solvent flooding. [ABSTRACT FROM AUTHOR]

Steam assisted gravity drainage (SAGD) is the established method for in situ bitumen extraction. However, natural gas powered generation of steam for the SAGD process results in large economic and environmental costs. Alcohol- and alkaline-based additives are emerging strategies to improve SAGD performance, and micromodels are uniquely well-suited to directly compare and quantify the effectiveness of additives with all other variables tightly controlled. The distinct effects of alcohol- and alkaline-based additives on the pore-scale mechanisms were quantified here using a representative high-pressure high-temperature glass micromodel with both optical and thermal imagings ( P =0.7 and 1.3 MPa; T =180 and 200 °C). Alcohol addition resulted in viscous fingering, some solvency, oil-wet trapping in the mobile zone, mainly water-in-oil emulsions, and moderate increases in production. In contrast, alkaline addition resulted in water-wet surface condition, emulsification of the bitumen into discrete oil-in-water droplets, and significantly increased production. Temperature profile data combined with optical results were also used to accurately determine the interface and expansion of discrete regions formed during the SAGD including steam chamber, hot water flow zone, mobile zone, and untouched bitumen zone. Alcohol provided only a slight improvement on the steam chamber growth, while alkaline additive expanded the steam chamber by over 10% and significantly improved the overall recovery. [ABSTRACT FROM AUTHOR]

There is increasing interest in synthesis of silicon dioxide (SiO 2) nanoparticles from agricultural biomass waste because the process is cost-efficient and eco-friendly. However, the application of rice straw SiO 2 nanoparticles as enhanced oil recovery (EOR) agents have not been examined in detail. Moreover, the pore-scale mechanisms governing the mobilization and displacement of resident oil during rice straw silica nanofluids (RS SNF) flooding is rarely reported in literature. In this study, SiO 2 nanoparticles (nanosilica) were synthesized from rice straw and characterized. Oil-water interfacial tension (IFT) and contact angles were measured to assess the performance of RS SNF as EOR agents. Pore-scale visualization experiments were conducted using 2-dimensional micromodel to identify the prevailing EOR mechanisms of RS SNF flooding. Significant reduction in oil-water IFT and contact angles were obtained in presence of RS SNF. These results were comparable to the performance of commercial silica nanofluids, suggesting that RS SNF could be utilized as favourable substitute to commercial SNF. The ideal rice straw nanosilica concentration for achieving optimum residual oil mobilization and microscopic sweep was identified as 0.1 wt% from pore-scale visualization experiments. At similar conditions, the oil retained (oil saturation) within the micromodel was determined by Image J software as 28.51% after 0.05 wt% RS SNF flooding and 23.73% after 0.1 wt% RS SNF flooding. The oil trapped in the micromodel after rice straw nanosilica–SDS and commercial nanosilica–SDS solutions injections were comparable at 19.35% and 18.33% respectively. The displacement efficiency and microscopic sweep was much higher when the synergy of nanoparticles and 0.2 wt% sodium dodecyl sulfate (SDS) solutions were injected into the micromodel due to the lowest oil-water IFT and contact angles achieved by SiO 2 /SDS solutions. The SiO 2 /SDS fluid front propagated uniformly and in piston-like movement pattern, suggesting that the impact of viscous force over capillary oil retention forces was significantly higher. During nanofluids flooding, uniform invasion of the displacing fluid was observed at the onset of fluid injection, the nanofluid become thicker whereas the oil become thinner with the advancement of the displacing front. However, fingering of the displacing fluid front was noticed with time, resulting in progression of displacement fronts with dendritic and dispersive patterns. Flow behaviours of synergy rice straw nanosilica and SDS as function of time. The rice straw nanofluid concentration is 0.05 wt% and SDS concentration is 0.2 wt%. The resident crude oil is coloured dark yellowish while the nanofluids is milky coloured. Flow direction is from left to right. [Display omitted] • Mechanisms of oil recovery by rice straw nanosilica (RS SNF) was studied. • Enhanced oil recovery performance of RS SNF was comparable to commercial nanosilica. • Optimum nanosilica concentration for maximum oil recovery was identified as 0.1wt%. • Fingering effect was more prominent in absence of surfactant. • SiO 2 /SDS fluids produced uniform and piston-like displacement front. [ABSTRACT FROM AUTHOR]

Numerical experiments are performed to evaluate the capability and examine the computational costs and tradeoffs of numerical and analytical approaches for apparent gas permeability calculation. Considering the dominance of capillary force in pore-level microstructures, two-phase distribution maps are constructed within micro- and nano-scale media using a quasi-static pore morphology-based technique. At each equilibrium step, the gas saturation profile is extracted to conduct single phase flow simulations and predict the gas effective permeability. To investigate the effect of gas slippage on the accuracy of the results, both Computational Fluid Dynamics (CFD) and Direct Simulation Monte Carlo (DSMC) techniques are applied in a wide range of gas pressures. The results reveal that the continuum theory is valid for a specific pore size and gas pressure range and its accuracy is strongly dependent on the Knudsen number value. DSMC simulation case studies demonstrate that in case of proper medium characterization, a tuned Klinkenberg correlation is capable of providing satisfying predictions within both slippage and transition flow regimes. [ABSTRACT FROM AUTHOR]

In this work, the oxygen transport in a nitrogen saturated matrix–fracture system at pore-scale was modelled. The microstructure of the porous matrix was modelled as a medium composed of circular particles periodically arranged. We considered the oxygen–coke reaction on the particle surface in order to simulate the combustion reaction encountered in an in-situ combustion process. The gas, coke and oxygen mass balances, and the gas momentum balance (assuming Newtonian fluid) were solved using a finite element solver. The oxygen distribution, in the matrix–fracture system, was studied in terms of the oxygen flow rate, fracture width and combustion reaction rate. It was found that increasing the oxygen flow rate, fracture width and combustion reaction rate favours the coke consumption. Moreover, these parameters increase the oxygen transport from the fracture to the porous zone. [ABSTRACT FROM AUTHOR]

There are numerous dead ends in micro-scale porous media and their special expansion-contraction structure incurs vortices in pore-scale flow. These vortices involve energy dissipation and thus cause extra flow resistance. Since there are no methods available for calculating this extra resistance, this work presents an innovative method for this purpose. It involves two steps including theoretical calculation and numerical simulation. Based on the well-known Hagen-Poiseuille equation, theoretical models are established for capillary tubes with different dead ends, both for calculating intrinsic flow resistance and Reynolds number. Computational fluid dynamics (CFD) simulation, based on the well-known Naiver-Stokes equations, is employed to characterize a pore-scale flow with vortices and to obtain the total flow resistance. The extra vortex-induced resistance can be further calculated by subtracting the theoretical intrinsic resistance from the simulated total resistance. This method is performed for five base cases, including a straight one without a dead end, a square-dead-end one, a quarter-circle-dead-end one, a triangle-dead-end one and one with combination of three dead ends. CFD simulations reveal that main and secondary vortices obviously exist in dead ends. Energy dissipation caused by vortices induces extra flow resistance. The extra resistance shows significant dependence on dead end shape and size as well as number. One possible reason is that a larger space of a dead end may promote the formation of more complex vortices thus causing larger extra resistance. The existence of numerous dead ends in a real micro-scale porous medium means formation of substantial numbers of shear-driven vortices and thus induction of huge increase in flow resistance. As a result, a real Q ~Δ p relationship may lie far away below the theoretical Q ~Δ p relationship determined by the Darcy's Law, thus undermining its dominance in characterizing pressure-driven pore-scale laminar flow. This work sheds light on insight of pore-scale flow and drops a hint that we may need corrections to this law in order to improve its characterization quality. • A method is innovated to evaluate the effect of vortices on flow resistance. • Theoretical models give the intrinsic resistance of dead-end tubes. • CFD simulations give the total flow resistance of dead-end tubes. • Subtracting the intrinsic resistance from the total one gives the extra one. • Extra resistance shows dependence on dead end shape & size and number. [ABSTRACT FROM AUTHOR]

Abstract: Network modeling is used to study the flow in porous media of Ellis and Herschel–Bulkley fluids, which model a large group of time-independent non-Newtonian fluids. Previous work is extended to include yield-stress and shear-thickening phenomena. We use two topologically-disordered networks representing a sand pack and Berea sandstone. Analytical expressions for the volumetric flow rate in a single tube are derived and implemented in each pore and throat to simulate single-phase flow in the pore space. An iterative technique is used to compute the relationship between flow rate and pressure gradient across the whole network. The single tube behavior is compared to that of the network. Experimental data in the literature are compared to the network simulation results to validate the model and investigate its predictive capabilities. Good agreement is obtained in many cases. The flow of yield-stress fluids in porous media is analyzed. Two algorithms to predict the network threshold yield pressure are implemented and compared to the numerically computed threshold yield pressure of the network. [Copyright &y& Elsevier]

Abstract: In this paper, we describe some novel multi-cycle water-alternating-gas injection (WAG) floods in 2-D etched glass oil-wet micromodels, which we have simulated using our recently developed three-phase, 3-D mixed-wet network model. A similar approach was described previously for WAG floods in a water-wet system [van Dijke, M.I.J., Sorbie, K.S., Sohrabi, M., Tehrani, D., Danesh, A., 2002. Three-phase flow in WAG processes in mixed-wet porous media: pore-scale network simulations and comparison with micromodel experiments. SPE 75192, Proc. SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, April 2002]. Although direct observation at the pore-scale is possible in the micromodel, some experimental data, required as input parameters for the network model, is not directly available. Therefore, a limited sensitivity study is performed, investigating the effects of the presence or absence of oil wetting films, around either gas or water, and the degree of oil wettability, leading to variation of the wetting order of gas and water. Based on these sensitivity calculations, oil wetting films are implemented around water only, in a limited fraction of all pores, such that the initial water pattern can be kept relatively sparse. Furthermore, the evidence support the micromodel being strongly oil-wet, since this more readily leads to gas displacing oil rather than water. With the estimated input parameters concerning films and wetting order, we then directly simulated the two oil-wet micromodel experiments, the first one starting with a water flood and the second one starting with a gas flood. Satisfactory agreement between simulation and experiment is found in terms of fluid distributions and oil recovery profiles. In addition, analysis of the displacement statistics, including the length (e.g. singles, doubles, multiples) and types of displacements (e.g. gas displacing oil), are broadly consistent with experiment, as far as this information is available. This paper illustrates the application of a network model to validate the local assumptions on the underlying pore-scale mechanism (on films and wettability), which are then used to predict what the emergent global properties are of the three-phase displacement processes in the micromodel. [Copyright &y& Elsevier]

A three-dimensional (3D) pore-scale network simulator is presented for modelling capillary-dominated three-phase flow in porous media where the wettability varies from pore to pore. The physics of weakly wetted systems has been included by allowing a pore to have any contact angle and, indeed, for each pore to have a different contact angle from a chosen distribution. An important complication arising from weakly wetting conditions is the absence of wetting films, which strongly reduces the continuity of the phases throughout the network. This reduction in phase continuity implies that during water-alternating-gas (WAG) injection processes a large number of phase clusters may form, that are disconnected from both inlet and outlet. Mobilisation of these clusters can happen through so-called multiple displacement chains, which involve a string of different phase clusters between inlet and outlet. We have explored the impact of these multiple displacement chains on WAG flow processes and the underlying three-phase flow mechanisms in a mixed-wet porous medium with the larger pores oil-wet. Assuming total absence of wetting films, we have varied the connectivity of the network (co-ordination number and dimension), the size of the network, the allowed maximum length of the displacement chains and the number of WAG cycles. The results are presented not only in terms of saturations and oil recovery, but also through statistics per flood of the length and type of displacement chains, the pore occupancy and through snapshots of the actual flood distributions (2D).From the simulations we conclude that for highly connected networks a steady state is reached after only a few WAG cycles, during which oil production ceases. However, in this state oil continues to be moved around within the network as a result of multiple displacement chains. The maximum allowed chain length has a substantial effect on the WAG saturation path, although the presence of longer chains during higher order WAG cycles is reduced for smaller networks and for networks with higher connectivity. For the investigated wettability state of the porous medium, four prevailing types of displacements emerge during each water flood and four different types emerge during each gas flood. When suppressing chains longer than two displacements in each flood one type disappears.Finally, we have listed some ways in which the predictions from the simulations may be tested experimentally both in core material and also in 2D micromodels. The latter type of experiments are particularly attractive, since lengths and types of displacement chains can be observed and counted directly. [Copyright &y& Elsevier]

We describe a pore- to reservoir-scale investigation of wettability variation and its impact on waterflooding. We use a three-dimensional pore-scale network model of a Berea sandstone to predict relative permeability and capillary pressure hysteresis. We successfully predict experimentally measured relative permeability data for the water-wet case, and demonstrate that the model captures experimentally observed trends in waterflood recovery for mixed-wet media. We then focus upon the effect of variations in initial water saturation associated with capillary rise above the oil–water contact (OWC). This may lead to wettability variations with height because the number of pore-walls which may be rendered oil-wet during primary drainage, increases as the oil saturation increases. We investigate empirical hysteresis models in which scanning curves are used to connect bounding drainage and waterflood curves for a given initial water saturation, and find that if wettability varies with initial water saturation, then the scanning water relative permeability curves predicted by the empirical model are significantly higher than those predicted by the network model. We then use a conventional simulator, in conjunction with the relative permeability curves obtained from the network and empirical models, to investigate the reservoir-scale impact of wettability variations on waterflooding. If the wettability varies with height above the OWC, we find that using the network model to generate scanning relative permeability curves yields a significantly higher recovery than using empirical models or assuming that the reservoir is uniformly oil-wet or water-wet. This is because the scanning water curves are generally low (characteristic of water-wet media), yet the residual oil saturation is also low (characteristic of oil-wet media). Our aim is to demonstrate that network models of real rocks may be used as a tool to predict wettability variations and their impact on field-scale flow. [Copyright &y& Elsevier]

Water phase trapping (WPT) is one of severe formation damage issues for the safe production in tight gas reservoirs. In this work, both pore-scale and core-scale investigation of the formation process of WPT were performed. Real-time observation of the water invasion and formation of trapped gas was achieved using visualized micromodel. Meanwhile, core flooding experiments including water imbibition and drainage experiments were conducted to analyze the responses of gas permeability and water saturation changes to the formation of WPT. The micromodel visualization experiments presented an intuitive gas-water two-phase flow scenarios which revealed the microscopic mechanisms of the WPT vividly. It pointed out that snap-off and circumfluous flow are the two major mechanisms to break the bulk gas flow and generate the trapped gas during WPT formation. The results of core flooding provided a causality link between the changes of gas permeability and water saturation, which showed a macroscopic consequence to the gas flow ability caused by WPT damage. These findings will benefit a better understanding of the formation process and damage mechanisms of WPT. • A pore-scale real-time observation of the formation process of trapped gas was achieved using visualized micromodel. • The synchronous change behavior of gas permeability and core water saturation during a WPT recycle was performed. • The microscopic dynamic mechanisms of WPT and macroscopic damage to gas flow ability were comprehensively achieved. [ABSTRACT FROM AUTHOR]

Water production in the oil industry has become so common that colloquial expressions such as "oil companies no longer produce oil, but water" have been unconsciously accepted in this industry. Nevertheless, water production is a serious issue in heavy oil fields with strong aquifers or fields under waterflooding for two reasons: It increases the costs affecting the economic viability of a project, and it has a serious environmental impact due to increasing energy consumption and C O 2 emissions. The root cause behind this problem is a phenomenon called Viscous Fingering, which appears mainly by the viscosity ratio between the phases. This study aims to understand better the Viscous Fingering phenomenon associated with a horizontal well in 3D. For the first time, a scaled horizontal well in a numerical constructed porous media was studied using a full 3D Computational Fluid Dynamics (CFD) model. The horizontal well was scaled using the Reynolds law of similarity from a real section of a horizontal well. While the porous media was made with the DEM physical model using spherical 7 m m particles, which allows reproducing rock properties such as permeability and porosity. This phenomenon was studied at three different scaled production rates, 1000, 1500, and 2000 bbl/d. Finally, three different oils were considered to study the influence of the viscosity ratio in the CFD modeling of the fingering. It was determined that CFD was capable of simulating Viscous Fingering for horizontal wells at the pore scale. Also, it could give information such as production and water cut-profiles, location and time of breakthrough, and specific locations of unrecoverable oil along the reservoir. The information given by the CFD approach could be useful for the development and improvement of completion and enhanced recovery techniques. Image 1 • A 3D CFD model to study Viscous Fingering at the pore scale considering horizontal wells is proposed. • A sensibility analysis on production rates was conducted, a reduction of oil recovery of was found. • A sensibility analysis on oil viscosity was conducted, a reduction of oil recovery of was found. • The CFD model at the pore scale was capable to predict the crossover from Capillary to Viscous Fingering. [ABSTRACT FROM AUTHOR]