Flow behaviour in the presence of wettability heterogeneities

The physical processes occurring during fluid flow and displacement within porous media having wettability heterogeneities have been investigated in specially designed heterogeneous visual models. The models were packed with glass beads, areas of which were treated with a water repellent to create wettability variations. Immiscible displacement experiments show visually the effect of wettability heterogeneities on the formation of residual oil and recovery due to capillary trapping. This work demonstrates by experiment the importance of incorporating reservoir heterogeneity into pore displacement analysis, essential for the correct interpretation of core data and for directing the route for scale-up of the processes to reservoir scale.     

Pore Scale and Macroscopic Displacement Mechanisms in Emulsion Flooding

The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control.     

Microbial Enhanced Oil Recovery in Fractional-Wet Systems: A Pore-Scale Investigation

Microbial enhanced oil recovery (MEOR) is a technology that could potentially increase the tertiary recovery of oil from mature oil formations. However, the efficacy of this technology in fractional-wet systems is unknown, and the mechanisms involved in oil mobilization therefore need further investigation. Our MEOR strategy consists of the injection of ex situ produced metabolic byproducts produced by Bacillus mojavensis JF-2 (which lower interfacial tension (IFT) via biosurfactant production) into fractional-wet cores containing residual oil. Two different MEOR flooding solutions were tested; one solution contained both microbes and metabolic byproducts while the other contained only the metabolic byproducts. The columns were imaged with X-ray computed microtomography (CMT) after water flooding, and after MEOR, which allowed for the evaluation of the pore-scale processes taking place during MEOR. Results indicate that the larger residual oil blobs and residual oil held under relatively low capillary pressures were the main fractions recovered during MEOR. Residual oil saturation, interfacial curvatures, and oil blob sizes were measured from the CMT images and used to develop a conceptual model for MEOR in fractional-wet systems. Overall, results indicate that MEOR was effective at recovering oil from fractional-wet systems with reported additional oil recovered (AOR) values between 44 and 80%; the highest AOR values were observed in the most oil-wet system.     

Modeling and Simulation of Microbial Enhanced Oil Recovery Including Interfacial Area

The focus of this paper is the derivation of a nonstandard model for microbial enhanced oil recovery (MEOR) that includes the interfacial area (IFA) between oil and water. We consider the continuity equations for water and oil, a balance equation for the oil–water interfacial area, and advective–dispersive transport equations for bacteria, nutrients, and biosurfactants. Surfactants lower the interfacial tension (IFT), which improves oil recovery. Therefore, the parametrizations of the IFT reduction and residual oil saturation are included as a function of the surfactant concentration in the model. We consider for the first time in context of MEOR, the role of IFA in enhanced oil recovery. The motivation to include the IFA is to model the hysteresis in the capillary pressure–saturation relationship in a physically based manner, to include the effects of observed bacteria migration toward the oil–water interface and the production of biosurfactants at the oil–water interface. A comprehensive 2D implementation based on two-point flux approximation and backward Euler is proposed. An efficient and robust linearization scheme is used to solve the nonlinear systems at each time step. Illustrative numerical simulations are presented. The differences in the oil recovery profiles obtained with and without IFA are discussed. The presented model can also be used to design new experiments toward a better understanding and eventually optimization of MEOR.     

复杂化学流体在多孔介质中的传质

化学驱油技术已从单一化学剂驱油发展到了复杂化学流体复合体系驱油。化学驱油过程中存在扩散、弥散、吸附、滞留、化学反应等一系列物理化学作用，影响化学剂在多孔介质中的传质过程。碱水驱油实验证明了单一化学剂在多孔介质中存在运移滞后；文中分析了上述物理化学作用，研究了复合体系各种化学剂的运移滞后及滞后差，指出综合吸附作用引起化学剂运移滞后，不同化学剂的运移滞后差导致色谱分离现象。在上述研究的基础上，提出 了吸附对流扩散方程，得到了解析解。并用该解析解处理实验资料，求出了方程中化学剂运移滞后系数和综合扩散系数等相应的参数，可描述和预测复杂化学流体在多孔介质中的传质过程。     

1D Simulations for Microbial Enhanced Oil Recovery with Metabolite Partitioning

We have developed a mathematical model describing the process of microbial enhanced oil recovery (MEOR). The one-dimensional isothermal model comprises displacement of oil by water containing bacteria and substrate for their feeding. The bacterial products are both bacteria and metabolites. In the context of MEOR modeling, a novel approach is partitioning of metabolites between the oil and the water phases. The partitioning is determined by a distribution coefficient. The transfer part of the metabolite to oil phase is equivalent to its ”disappearance,” so that the total effect from of metabolite in the water phase is reduced. The metabolite produced is surfactant reducing oil–water interfacial tension, which results in oil mobilization. The reduction of interfacial tension is implemented through relative permeability curve modifications primarily by lowering residual oil saturation. The characteristics for the water phase saturation profiles and the oil recovery curves are elucidated. However, the effect from the surfactant is not necessarily restricted to influence only interfacial tension, but it can also be an approach for changing, e.g., wettability. The distribution coefficient determines the time lag, until residual oil mobilization is initialized. It has also been found that the final recovery depends on the distance from the inlet before the surfactant effect takes place. The surfactant effect position is sensitive to changes in maximum growth rate, and injection concentrations of bacteria and substrate, thus determining the final recovery. Different methods for incorporating surfactant-induced reduction of interfacial tension into models are investigated. We have suggested one method, where several parameters can be estimated in order to obtain a better fit with experimental data. For all the methods, the incremental recovery is very similar, only coming from small differences in water phase saturation profiles. Overall, a significant incremental oil recovery can be achieved, when the sensitive parameters in the context of MEOR are carefully dealt with.     

Hydrodynamic models of the residual oil distribution in water-flood reservoirs

Models of the residual oil saturation distribution are proposed for linear, axisymmetric, and general flows. The steady displacing fluid flow model makes it possible to find equilibrium residual oil saturation distributions corresponding to given flow regimes by treating the porous medium with capillary-trapped oil as a medium with permeability that depends on the displacement conditions. The dynamics of the mobilized globules of the residual oil are excluded from consideration. The simulation results indicate that the residual oil saturation distribution after stimulation of the wash-out zone by means of enhanced oil recovery techniques is generally essentially nonuniform. Moscow. Translated from Izvestiya Rossiiskoi Akademii Nauk, Mekhanika Zhidkosti i Gaza, No. 3, pp. 98–104, May–June, 2000.     

Coreflooding Studies to Evaluate the Impact of Salinity and Wettability on Oil Recovery Efficiency

In this work, coreflood studies were carried out to determine the recovery benefits of low salinity waterflood compared to high salinity waterflood and the role of wettability in any observed recovery benefit. Two sets of coreflood experiments were conducted; the first set examined the EOR potential of low salinity floods in tertiary oil recovery processes, while the second set of experiments examined the secondary oil recovery potential of low salinity floods. Changes in residual oil saturation with variation in wettability, brine salinity and temperature were monitored. All the coreflood tests gave consistent increase in produced oil, corresponding to reduction in residual oil saturation and increase in water-wetness (for the second set of experiments) with decrease in brine salinity and increase in brine temperature.     

Pore-scale flow characterization of low-interfacial tension flow through mixed-wet porous media with different pore geometries

The low-interfacial tension flow through porous media occurs in surfactant-based enhanced oil recovery (EOR), soil clean-up, underground removal of the non-aqueous phase liquid and dense non-aqueous phase liquid, etc. In surfactant-based EOR processes, numerous works have been carried out to characterize - either qualitatively or quantitatively - the micro- and macro-scale flow behavior. What has been lacking is to link the statistics of oil blobs population (e.g., distribution of blob length and diameter) to the pore-scale phenomena and macro-scale quantities. In particular, no work has been reported to elucidate the effect of the ratio of pore body to throat diameter (i.e., aspect ratio) on the pore-scale characterization based on the blobs population statistics. The significance of the aspect ratio lies in that it describes the geometry of a porous medium and is one of the foremost morphological features. The aspect ratio is also one of the fundamental factors governing the pore-level events. This study presents the effect of aspect ratio on the statistical distribution of the blob length and equivalent diameter and links the blobs population statistics to the observed pore-level events. The pore-scale variation of the ratio of viscous-to-capillary forces acted on the oil blobs at the threshold of displacement is utilized to characterize the effect of blob length distribution at different aspect ratios. It also provides some insight into correlating the change in oil recovery efficiency and capillary number, by change in aspect ratio, with the change in blobs population statistics.     

非牛顿流体在非均质油藏渗流压力场实验

在非均质油藏模型上进行非牛顿流体流动物理模拟实验，对比研究水驱、聚合物驱和交联聚合物对提高石油采收率的影响．通过布置高精度的压差传感器测量不同驱替过程模型中的渗流压力场的动态变化，成胶后的交联聚合物封堵了高渗条区，改变了油藏内流体流动方向，驱替出低渗区内油，提高了采收率．     

Microtomography of Imbibition Phenomena and Trapping Mechanism

Water imbibition during the waterflooding process of oil production only sweeps part of the oil present. After water disrupts the oil continuity, most oil blobs are trapped in porous rock by capillary forces. Developing an efficient waterflooding scheme is a difficult task; therefore, an understanding of the oil trapping mechanism in porous rock is necessary from a microscopic viewpoint. The development of microfocused X-ray CT scanner technology enables the three-dimensional visualization of multiphase phenomena in a pore-scale. We scanned packed glass beads filled with a nonwetting phase (NWP) and injected wetting phase (WP) in upward and downward injections to determine the microscopic mechanism of immiscible displacement in porous media and the effects of buoyancy forces. We observed the imbibition phenomena for small capillary numbers to understand the spontaneous imbibition mechanism in oil recovery. This study is one of the first attempts to use a microfocused X-ray CT scanner for observing the imbibition and trapping mechanisms. The trapping mechanism in spontaneous imbibition is determined by the pore configuration causing imbibition speed differences in each channel; these differences can disrupt the oil continuity. Gravity plays an important role in spontaneous imbibition. In upward injection, the WP flows evenly and oil is trapped in single or small clusters of pores. In downward injection, the fingering phenomena determine the amount of trapped oil, which is usually in a network scale. Water breakthrough causes dramatic decrease in the oil extraction rate, resulting in lower oil production efficiency.     

Effective Relative Permeabilities and Capillary Pressure for One-Dimensional Heterogeneous Media

The paper presents an analytical construction of effective two-phase parameters for one-dimensional heterogeneous porous media, and studies their properties. We base the computation of effective parameters on analytical solutions for steady-state saturation distributions. Special care has to be taken with respect to saturation and pressure discontinuities at the interface between different rocks. The ensuing effective relative permeabilities and effective capillary pressure will be functions of rate, flow direction, fluid viscosities, and spatial scale of the heterogeneities.The applicability of the effective parameters in dynamic displacement situations is studied by comparing fine-gridded simulations in heterogeneous media with simulations in their homogeneous (effective) counterparts. Performance is quite satisfactory, even with strong fronts present. Also, we report computations studying the applicability of capillary limit parameters outside the strict limit.     

Volume Conservation of the Intermediate Phase in Three-Phase Pore-Network Models

Quasi-static rule-based network models used to calculate capillary dominated multi-phase transport properties in porous media employ equilibrium fluid saturation distributions which assume that pores are fully filled with a single bulk fluid with other fluids present only as wetting and/or spreading films. We show that for drainage dominated three-phase displacements in which a non-wetting fluid (gas) displaces a trapped intermediate fluid (residual oil) in the presence of a mobile wetting fluid (water) this assumption distorts the dynamics of three-phase displacements and results in significant volume errors for the intermediate fluid and erroneous calculations of intermediate fluid residual saturations, relative permeabilities and recoveries. The volume errors are associated with the double drainage mechanism which is responsible for the mobilization of waterflood residual oil. A simple modification of the double drainage mechanism is proposed which allows the presence of a relatively small number of partially filled pores and removes the oil volume errors.     

Numerical study of non-uniqueness of the factors influencing relative permeability in heterogeneous porous media by lattice Boltzmann method

The effects of capillary number Ca and viscosity ratio M on non-uniqueness of the relative permeability (RP) – wetting saturation (S_w) relationships of steady-state immiscible two-phase flow in the heterogeneous porous media are studied by a developed lattice Boltzmann method (LBM). In this work, it is suggested that the non-uniqueness of capillary number Ca and viscosity ratio M influencing RP–S_w curves is due to the presence of the heterogeneity of porous media. For the different Ca and M, the RP–S_w curves in the homogenous and heterogeneous porous media with the same porosity are discussed in detail. It is found that (1) the pore-size distributions in porous media have significant effect on the RPs of both wetting phase (WP) and non-wetting phase (NWP); (2) the heterogeneity of porous media has negative effect on the increment of the RP of NWP caused by the large capillary number. The lubricating effect is strongly dependent on pore-size distributions in porous media; and (3) the large viscosity ratio increases the RP of NWP, while it has little effect on the RP of WP. The effect on the RP of NWP may be magnified by the heterogeneity of porous media.     

Radial Oil–Water Transport Toward an Extraction Well

We apply steady-state capillary-controlled upscaling in heterogeneous environments. A phase may fail to form a connected path across a given domain at capillary equilibrium. Moreover, even if a continuous saturation path exists, some regions of the domain may produce disconnected clusters that do not contribute to the overall connectivity of the system. In such cases, conventional upscaling processes might not be accurate since identification and removal of these isolated clusters are extremely important to the global connectivity of the system and the stability of the numerical solvers. In this study, we address the impact of percolation during capillary-controlled displacements in heterogeneous porous media and present a comprehensive investigation using random absolute permeability fields, for water-wet, oil-wet and mixed-wet systems, where J-function scaling is used to relate capillary pressure, porosity and absolute permeabilities in each grid cell. Important information is revealed about the average connectivity of the phases and trapping at the Darcy scale due to capillary forces. We show that in oil-wet and mixed-wet media, large-scale trapping of oil controlled by variations in local capillary pressure may be more significant than the local trapping, controlled by pore-scale displacement.     

New Trapping Mechanism in Carbon Sequestration

The modes of geologic storage of CO₂ are usually categorized as structural, dissolution, residual, and mineral trapping. Here we argue that the heterogeneity intrinsic to sedimentary rocks gives rise to a fifth category of storage, which we call local capillary trapping. Local capillary trapping occurs during buoyancy-driven migration of bulk phase CO₂ within a saline aquifer. When the rising CO₂ plume encounters a region (10⁻² to 10⁺¹m) where capillary entry pressure is locally larger than average, CO₂ accumulates beneath the region. This form of storage differs from structural trapping in that much of the accumulated saturation will not escape, should the integrity of the seal overlying the aquifer be compromised. Local capillary trapping differs from residual trapping in that the accumulated saturation can be much larger than the residual saturation for the rock. We examine local capillary trapping in a series of numerical simulations. The essential feature is that the drainage curves (capillary pressure versus saturation for CO₂ displacing brine) are required to be consistent with permeabilities in a heterogeneous domain. In this work, we accomplish this with the Leverett J-function, so that each grid block has its own drainage curve, scaled from a reference curve to the permeability and porosity in that block. We find that capillary heterogeneity controls the path taken by rising CO₂. The displacement front is much more ramified than in a homogeneous domain, or in a heterogeneous domain with a single drainage curve. Consequently, residual trapping is overestimated in simulations that ignore capillary heterogeneity. In the cases studied here, the reduction in residual trapping is compensated by local capillary trapping, which yields larger saturations held in a smaller volume of pore space. Moreover, the amount of CO₂ phase remaining mobile after a leak develops in the caprock is smaller. Therefore, the extent of immobilization in a heterogeneous formation exceeds that reported in previous studies of buoyancy-driven plume movement.     

Simulations of Microbial-Enhanced Oil Recovery: Adsorption and Filtration

In the context of microbial-enhanced oil recovery (MEOR) with injection of surfactant-producing bacteria into the reservoir, different types of bacteria attachment and growth scenarios are studied using a 1D simulator. The irreversible bacteria attachment due to filtration similar to the deep bed filtration (DBF) is examined along with the commonly used reversible equilibrium adsorption (REA). The characteristics of the two models are highlighted. The options for bacteria growth are the uniform growth in both phases and growth of attached bacteria only. It is found that uniform growth scenario applied to filtration model provides formation of two oil banks during recovery. This feature is not reproduced by application of REA model or DBF with growth in attached phase. This makes it possible to select a right model based on the qualitative analysis of the experimental data. A criterion is introduced to study the process efficiency: the dimensionless time at which average recovery between pure water injection and maximum surfactant effect is reached. This characteristic recovery period (CRP) was studied as a function of the different MEOR parameters such as bacterial activity, filtration coefficients, and substrate injection concentrations. For both growth scenarios, there is a zone of optimal activity at which the CRP is minimal. Dependence of the CRP on substrate concentration for uniform growth scenario has also an optimal zone. Therefore, growth rate and the substrate concentration should be above a certain threshold value and still not be too high to obtain the minimum CRP. On the other hand, no such zone was found if the bacteria could grow only in the attached phase. Dependencies on both the injected concentration and filtration coefficient are monotonous in this case.     

In-Situ Capillary Trapping of CO<Subscript>2</Subscript> by Co-Injection

Co-injection of water with CO₂ is an effective scheme to control initial gas saturation in porous media. A fractional flow rate of water of approximately 5–10% is sufficient to reduce initial gas saturations. After water injection following the co-injection, most of the gas injected in the porous media is trapped by capillarity with a low fractional volume of migrating gas. In this study, we first derive an analytical model to predict the gas saturation levels for co-injection with water. The initial gas saturation is controlled by the fractional flow ratio in the co-injection process. Next, we experimentally investigate the effect of initial gas saturation on residual gas saturation at capillary trapping by co-injecting gas and water followed by pure water injection, using a water and nitrogen system at room temperature. Depending on relative permeability, initial gas saturation is reduced by co-injection of water. If the initial saturation in the Berea sandstone core is controlled at 20–40%, most of the gas is trapped by capillarity, and less than 20% of the gas with respect to the injected gas volume is migrated by water injection. In the packed bed of Toyoura standard sand, the initial gas saturation is approximately 20% for a wide range of gas with a fractional flow rate from 0.50 to 0.95. The residual gas saturation for these conditions is approximately 15%. Less than approximately 25% of the gas migrates by water injection. The amount of water required for co-injection systems is estimated on the basis of the analytical model and experimental results.     

Dispersion Stability and Transport of Nanohybrids through Porous Media

Single-walled carbon nanotube-silica nanohybrid particles are a very promising material that could be used for enhanced oil recovery because of their interfacial activity. To demonstrate the basic principle, aqueous nanohybrid particle dispersions were evaluated by looking at the effect of pH, surfactant, and polymer. The results showed that pH did not have significant effect on the dispersion stability of nanohybrid particles. Although surfactant could improve the dispersion stability, it reduced the interfacial activity of the nanohybrid particles, causing them to stay in the aqueous phase. The best nanohybrid particle dispersion stability was found upon polymer addition, where the dispersions were stable for more than a week even at low polymer concentration (50?ppm). One-dimensional sand-pack studies were performed to evaluate the flow of the nanohybrid particles through porous media. The results showed that most of the nanohybrid particles (>99%) could pass through a column packed with glass beads while a measurable fraction of the particles was retained in the column packed with crushed Berea. When the columns contained a residual saturation of decane, additional nanohybrid particles were retained at the oil/water interface in both glass beads and crushed Berea sand media. The sand pack studies showed that not only can the nanohybrid particles flow through porous media but also about half of the particles injected will go the O/W interface when the porous medium contains a residual saturation of hydrocarbon, where they could be used to support a catalytic conversion of components of the oil in reservoirs.