Wetting Phase Research Articles

Existence of a Weak Solutionto the Two-Dimensional Filtration Problem in a Thin Poroelastic Layer

The paper considers a mathematical model of the joint motion of two immiscible incompressible fluids in a poroelastic medium. This model is a generalization of the classical Musket-Leverett model, in which porosity is considered to be a given function of the spatial coordinate. The model under study is based on the mass conservation equations for liquids and the porous skeleton, Darcy's law for liquids, which takes into account the movement of the porous skeleton, the Laplace formula for capillary pressure, the Maxwell-type rheological equation for porosity, and the "system as a whole" equilibrium condition. In the thin layer approximation, the original problem is reduced to the successive determination of the porosity of the solid skeleton and its velocity. Then an elliptic-parabolic system is derived for the “reduced pressure” and saturation of the wetting phase. Its solution is understood in a generalized sense due to the degeneration on the solution of the equations of the system. The proof of the existence theorem is carried out in four stages: regularization of the problem, proof of the physical maximum principle for saturation, construction of Galerkin approximations, passage to the limit in regularization parameters based on the method of compensated compactness.

Relative permeability of two-phase flow through rough-walled fractures: Effect of fracture morphology and flow dynamics

This paper considers the influence of geometry and flow conditions on the relative permeability of wetting and non-wetting components of multiphase flows through fractures. Using an explicit immiscible two-phase fracture-flow model, 945 multiphase flow simulations were conducted on artificially-generated fracture geometries. These simulations accounted for the effects of initial fracture roughness, confining stress, pressure gradient, surface tension and volume fraction on the fracture flow. Time averaged relative permeabilities were recorded for both the wetting and non-wetting phases in each of the simulations.The simulation results demonstrate that relative permeability curves are strongly influenced by contact area, fracture morphology and competition between viscous and capillary forces. Increasing the normal stress creates more contact in the fracture plane, which increases interference between the fluid phases. The effect is more pronounced in fractures with strongly correlated apertures where the chance of fluid trapping is increased. The relative importance of viscous forces compared to capillary forces was investigated by applying different pressure gradients to the fluids. Increasing the pressure gradient tends to cause the flow paths to segregate and the relative permeability curves approach the linear model, in agreement with experimental results.From these observations, two new relative permeability models were introduced to describe the behavior of wetting and non-wetting phases in fractures. The performance of the new models were compared to other published relative permeability models for fracture geometries. The new models were found to more accurately predict the relative permeability when compared to the other available models for both the wetting and non-wetting phases.

Numerical simulations of high viscosity DNAPL recovery in highly permeable porous media under isothermal and non-isothermal conditions

We developed a decimetric size model based on coupling generalized Darcy's law and heat-transfer equations to model viscous dense non-aqueous phase liquid (DNAPL) pumping through highly permeable porous media under non-isothermal conditions. The presence of fingering and non-wetting phase ganglia was modeled through an unsteady capillary diffusion coefficient and an arbitrary heterogeneous permeability field. The model was validated using existing experimental data of a simple case, an oil injection in a 2D tank packed with glass beads. Next, we compared the results of this model against a DNAPL extracting situation in the 2D tank to better understand the two-phase flow behavior in highly permeable porous media. We found that natural convection during heating plays an essential role in heat transfer, especially in the wetting phase zone. By adding the dynamic effect (unsteady conditions) we were better able to describe the presence of the ganglia in porous media. We observed good agreement between modeled and experimental oil saturation curves until the breakthrough point, with a mean relative error of about 10% for low and high flow rates, and 8% and 16% after breakthrough for low and high flow rates, respectively. Extracting viscous oil at low flow rates and high temperature generates less fingering and is well described by the generalized Darcy's law. The remobilization of residual non-wetting ganglia after the breakthrough point at the outlet is, however, difficult to simulate using the generalized Darcy's law. In the end, we treated this issue by using a perturbed permeability field to simulate the observed fingering in the 2D tank.

An Improved Capillary Pressure Model for Fractal Porous Media: Application to Low-Permeability Sandstone

Capillary pressure is a crucial input in reservoir simulation models. Generally, capillary pressure measurements are expensive and time-consuming; therefore, there is a limitation on the number of cores tested in the laboratory. Accordingly, numerous capillary pressure models have been suggested to match capillary pressure curves and overcome this limitation. This study developed a new fractal capillary pressure model by depicting the porous system as a bundle of tortuous triangular tubes. The model imitates the pores’ angularity, providing a more accurate representation of the pore system than smooth circular openings. Moreover, triangular tubes allow the wetting phase to be retained in the tube’s corners. A genetic algorithm was employed to match the capillary pressure curves and obtain the proposed model’s parameters. Capillary pressure data of eight low-permeability sandstone samples from the Khatatba formation in the Western Desert of Egypt were utilized to test the proposed model. The results revealed that the developed model reasonably matched the laboratory-measured data.

Theoretical comparison of two setups for capillary pressure measurement by centrifuge

There are several approaches for the calculation of capillary pressure curves in porous media including the centrifuge method. In this work, a new installation of centrifuge test is introduced and compared with the traditional setup. In the first setup, which is a standard approach in labs, the core face closest to the rotational axis is open to the non-wetting phase, while the farthest face is open to the wetting phase where strictly co-current flow is generated in rotations; labeled Two-Ends-Open (TEO). In the second setup, which is proposed as a new approach, only the outer radius surface is open and is exposed to the light non-wetting phase; labeled One-End-Open (OEO). This setup strictly induces counter-current flow. The two systems and their corresponding boundary conditions are formulated mathematically and solved by a fully implicit numerical solver. The TEO setup is validated by comparison with commercial software. Experimental data from the literature are used to parameterize the models. It is mathematically, and with examples, demonstrated that the same equilibrium is obtained in both systems with the same rotational speed, and changing the installation does not influence the measured capillary pressure. This equilibrium state is only dependent on the rotational speed, rock capillary pressure properties, and fluid densities, not the installation geometry, relative permeabilities, or fluid viscosities. However, the dynamic transition trend and saturation profiles were found to be dependent on the applied installation. It was observed that the OEO setup takes almost identical equilibration time as the TEO setup for mixed-wet states, although it needed much longer time in water-wet states. The presence of threshold capillary pressure significantly increased the time scale of the OEO setup. Also, it was found that in contradiction to the TEO setup, the dynamic saturation profile in OEO was rarely influenced by viscosity ratio. To conclude, the performed history matching analysis demonstrated that the OEO setup can be applied for the calculation of counter-current relative permeability from the production data with reasonable accuracy.

A Novel Model of Counter-Current Imbibition in Interacting Capillaries with Different Size Distribution

The imbibition phenomenon widely exists in nature and industrial applications. It is of great significance to study the mechanism of imbibition and the influence laws of related factors. In this paper, based on the assumption of interacting capillaries, a capillary bundle model of counter-current imbibition is established. In addition, the characteristics of imbibition and the influences of capillary size and fluid viscosity are analyzed. The results show that water is imbibed into the smaller capillaries and expelled from the larger capillaries. The rate of the meniscus in water-imbibition capillaries is proportional to the square root of time. In the interacting capillaries, oil production by counter-current imbibition decreases and then increases gradually with the increase of the capillary diameter difference. When the total cross-sectional area of the capillary remains unchanged, the cross-sectional area of the total water-imbibition capillaries is affected by the size distribution of the capillaries. The larger the viscosity of the non-wetting phase, the more uneven the imbibition front, the lower the imbibition efficiency. The higher the viscosity of the wetting phase, the more uniform the imbibition front, and the higher the imbibition efficiency.

A novel model for oil-water two-phase relative permeability of shale formation during flowback based on fractal method

As an abundant type of unconventional hydrocarbon resources on the earth, shale oil has been widely concerned by scholars across the world. During flowback period, flow-back resistance of fracturing fluids increases because of the existence of shale oil. Therefore, it is of practical significance to study the flow-back capability of fracturing fluid for high well performance. In this paper, fractal method of porous media has been used for calculation of relative permeability of oil-water two phase flow in shale pores. First, we built up flow equation of single nanopore with four layers: boundary layer, bulk wetting phase layer, oil-water two phase layer, and nonwetting phase layer. Furthermore, boundary slip, boundary, viscosity change in boundary layer and threshold pressure gradient is considered for correction flow rate equation. The pores of shale matrix can be simplified into capillary bundle model, and fractal theory is suitable for this model. Aperture fractal dimension and tortuosity fractal dimension is used to expand its scale to porosity media with fractal method. Then the model is verified by experimential results and classic models. Furthermore, serval main factors affecting the relative permeability of water are primarily analyzed, and the more essential factors out of the aforementioned ones are extracted and further studied. The results show that with the increase in the thickness of oil-water two phase layer, the relative permeability of water is affected more seriously; The relative permeability of water is positively correlated with slip length and thickness of boundary layer. This work provides a more convenient approach to calculate relative permeability with no experiments, and provide permeability for numerical simulation in flow back period.

Influence of wettability upon IP characteristics of rocks in low porosity and low permeability reservoirs

The induced polarization characteristics of oil-bearing rocks in reservoirs can play a key role in reservoir evaluation in the stage of oil and gas exploration and development. With the continuous advancement of oil and gas exploration, low porosity and low permeability reservoirs have become important objects of exploration and development, but the research on the response mechanism of complex resistivity of reservoir rocks is still not deep enough. In this study, the reservoir rocks with low porosity and low permeability were taken as the research object. By measuring the complex resistivity of oil-bearing rock samples under two different wetting conditions, the amplitude and phase of complex resistivity of reservoir rocks under different oil saturation were obtained. The MGEMTIP model was used to invert the low-frequency data and calculate IP parameters such as DC resistivity and polarizability to study the induced polarization characteristics of reservoir rocks under different oil saturation conditions. The results showed that the DC resistivity of reservoir rocks increased with the increase of oil saturation, and the trend was influenced by the conductivity of oil-water mixture and rock surface. When the oil saturation was about 45%, for the same rock, with the increase of contact angle before and after aging, the DC resistivity had a certain downward trend. Under low oil saturation, the polarizability of relatively hydrophilic rocks tended to increase with the increase of oil saturation. After the wettability was changed, the reservoir rocks were relatively hydrophobic, and the polarizability first decreased with the increase of oil saturation, and then under the influence of Maxwell-Wagner polarization, the polarizability of the rocks increased with the increase of oil saturation. Therefore, the characteristics of induced polarization of reservoirs with different wettability can provide physical basis for oil reservoir exploration, development and evaluation.

Low salinity water flooding: Evaluating the effect of salinity on oil and water relative permeability curves using coupling of DLVO and geochemical reactions

Enhancing the oil recovery of carbonate reservoirs with acidic oil depends on injected brine composition and salinity throughout the low salinity water flooding. The typical description of this phenomenon on oil and water relative permeability curves is being put forward by the process-dependent interpolation function, which barely addresses the underlying fundamentals governing the direct impact of wettability alteration and geochemical reactions on flow saturation functions. The main objective of this work is to perform an integrated investigation of the effect of salinity on oil and water relative permeability curves by dynamic coupling of the Derjaguin, Landau, Verwey, and Overbeek (DVLO) theory and geochemical reactions. We studied both the single and two-phase systems using the basis of the geochemical reactions to track the variations of the wetting and non-wetting phase relative permeability curves. In the single-phase scenario, the results show the superiority of the reactive flow modeling technique with kinetic-controlled reactions, in the range between [2–4] of the Damkohler number, to yield a better result for the experimental effluent ions' concentrations than the equilibrium approach. In addition, the single-phase results under dynamic conditions propose Civan correlation as the best predictor of residual resistance factor (RRF) by numerically adjusting the correlation of coefficients based on the physical variables - salinity, dimensionless consumed ion concentration, and Peclet number. Accordingly, the results indicate a novel linkage between the single-phase and two-phase results in the sense that RRF under single-phase mode can be used to estimate the change in the wetting phase relative permeability under the two-phase mode. The single-phase methodology provides the capability for an improvement – up to 15% - in the prediction of the pressure drop curve. For two-phase cases, our procedure involved coupling the characterized geochemical reactions and the DLVO theory to consider the effect of injected water composition on contact angle as the static two-phase parameter. The phase-field method is coupled with DLVO theory to calculate the relative permeability curves for the non-wetting phase, which corresponds to the contact angle at each simulation time step. The two-phase results indicate an improvement – up to 30% - in the prediction of the recovery factor curve, on a history-matching basis, using the DLVO theory with contact angle-dependent correlation of non-wetting phase relative permeability curve. The main novelties of this study are using the single-phase dynamic permeability impairment results in calculating the variation of the wetting-phase relative permeability curve. Moreover, dynamic coupling of DLVO and non-linear contact angle-dependent correlation is used to calculate the non-wetting phase relative permeability curve. According to these novelties, more accurate prediction of the laboratory production profiles can be obtained.

Interface potential and line tension for Bose-Einstein condensate mixtures near a hard wall

Within Gross-Pitaevskii (GP) theory we derive the interface potential V (l) which describes the interaction between the interface separating two demixed Bose-condensed gases and an optical hard wall at a distance l. Previous work revealed that this interaction gives rise to extraordinary wetting and prewetting phenomena. Calculations that explore non-equilibrium properties by using l as a constraint provide a thorough explanation for this behavior. We find that at bulk two-phase coexistence, V (l) for both complete wetting and partial wetting is monotonic with exponential decay. Remarkably, at the first-order wetting phase transition, V(l) is independent of l. This anomaly explains the infinite continuous degeneracy of the grand potential reported earlier. As a physical application, using V(l) we study the three-phase contact line where the interface meets the wall under a contact angle theta. Employing an interface displacement model we calculate the structure of this inhomogeneity and its line tension tau. Contrary to what happens at a usual first-order wetting transition in systems with short-range forces, tau does not approach a nonzero positive constant for theta going to zero, but instead approaches zero (from below) as would be expected for a critical wetting transition. This hybrid character of tau is a consequence of the absence of a barrier in V(l) at wetting. For a typical V(l) we provide a conjecture for the exact line tension within GP theory.

Characteristic Forced and Spontaneous Imbibition Behavior in Strongly Water-Wet Sandstones Based on Experiments and Simulation

Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water.

Imbibition Retention in the Process of Fluid Replacement in Tight Sandstone Reservoir

“Fracture network stimulation and oil-water infiltration and replacement” are recent attempts to effectively produce oil from tight reservoirs. On the one hand, the formation can be fractured by the fracturing fluid, which can carry proppant into fractures. On the other hand, the fracturing fluid can spontaneously infiltrate into the pores under the action of capillary pressure to displace the oil phase, thereby enhancing the oil recovery. To distinguish imbibition and displacement processes during fluid replacement in tight reservoirs is difficult, and the effect of these two processes is also vaguely defined. In this study, an experimental method that can visualize the imbibition and displacement process is proposed by combining the core slice displacement experiment. Based on this method, the process of imbibition and displacement can be effectively distinguished, and imbibition retention rate can be quantitatively characterized. The effectiveness of this method is proved by taking the core of Chang 7 tight sandstone reservoir in the Ordos Basin as the research object. The results show that the force direction of the fluid under imbibition is related to the wettability, and it is always from the wetting phase to the nonwetting phase, while the force direction of fluid under displacement is mainly related to the directivity of displacement pressure difference. Based on the difference of force action, imbibition and displacement can be quantitatively characterized, respectively. During the imbibition process, the peak value of the NMR curve corresponding to the small pore throat shifts to the left, and the signal amplitude increases. During the displacement process, the peak value of the NMR curve corresponding to the small pore throat has no obvious shift, nor signal amplitude change, but the peak value of the curve corresponding to the large pore throat shifts to the right. The results also indicate that there is an exponential negative correlation between imbibition retention rate and gas permeability. The greater the gas permeability is, the smaller the imbibition retention rate is.

Analysis of non‐isothermal multiphase flows in porous media

We consider an initial‐boundary value problem for a degenerate fully nonlinear parabolic system modeling coupled two‐phase flow and heat transport through porous media. The two‐phase fluid system consists of incompressible wetting phase and compressible nonwetting phase, such that the density of the nonwetting phase is a function of the phase pressure and temperature. To simplify the structure of the problem and overcome degeneracies in transport coefficients, the mathematical model is reformulated by using the feature of the so‐called global pressure and the capillary pressure potential. Under physically relevant assumptions on the data of the problem and taking the initial conditions and mixed boundary conditions into consideration, we prove a global existence of a weak solution to this system on any physically relevant time interval.

Insights into the fluid wetting law and fractal characteristics of coal particles during water injection based on nuclear magnetic resonance

In order to reveal the migration mechanism of dynamic water between coal particles in the process of coal seam water injection, in this study, nuclear magnetic resonance experiments (NMR) were carried out on wetted coal samples, the transverse relaxation time (T2) spectra of samples presenting different degrees of metamorphism and particle size ranges were measured over different time periods of the wetting process, and the fractal dimension (DNMR) of the wetting phase distribution in the migration channel was calculated. (1) The average values of T2g decrease percentage Δ of the three coal samples are 84%, 71.25%, and 57.75%, indicating that the order of the wettability strength is Daliuta coal sample (DLT) > Xinglongzhuang coal sample (XLZ) > Qincheng (QC), this shows that the coal samples are more easily wetted as the degree of metamorphism decreases. (2) Sodium dodecyl sulfate (SDS) will make the wetting process between coal and water smoother, and in the range of 60–80 mesh and 100–120 mesh particle size, compared to the solution properties change, the particle size has relatively little influence on the wetting process when its change is not large. (3) The surface tension reduction caused by the addition of surfactants in the water, the narrowing of the pore space caused by the reduction of the overall size of the particles, and the decrease of the particle surface wettability caused by the increase in the metamorphic degree of coal sample will lead to the decrease of DNMR measured in the experiment. Based on the above research, it can provide a theoretical basis for improving the effect of coal seam wetting and dust reduction.

THE CORRELATION BETWEEN FLUID FLOW AND HEAT TRANSFER OF UNSATURATED SHALE RESERVOIR BASED ON FRACTAL GEOMETRY

The dissimilar multi-scale structures of shale to conventional reservoirs make it a challenge to understand the fluid flow and heat transfer through unsaturated shale formations. In this paper, the pore structure and moisture content of shale samples are measured by low-field nuclear magnetic resonance technique and thermogravimetric differential scanning calorimetry test, respectively. A pore-scale model is accordingly developed for the immiscible two-phase fluid flow and heat conduction through unsaturated shale based on the statistically self-similar fractal scaling law of pore size distribution. The analytical expressions of effective and relative permeability, as well as effective thermal conductivity (ETC), are proposed, which indicate good agreement with experimental results. It has been shown that the capillary pressure and gas slippage play important role in multiphase flow through unsaturated shale. Both pore and tortuosity fractal dimensions show significant influence on the relative permeability for nonwetting phase (RPNW), while they indicate the marginal effect on the relative permeability for the wetting phase (RPW). The ETC decreases with the increase of pore and tortuosity fractal dimensions, and it is positively and negatively correlated with RPW and RPNW, respectively. The correlation between ETC and relative permeability is found to follow a logistic function. The present fractal model can characterize the multiscale structures of shale reservoirs and may help understand transport mechanisms of immiscible multiphase flow and heat transfer through unsaturated shale.

Pore structure analysis and permeability prediction of shale oil reservoirs with HPMI and NMR: A case study of the Permian Lucaogou Formation in the Jimsar Sag, Junggar Basin, NW China

The pore structure characteristics and formation permeability are important reservoir information for the development of shale oil. The pore structures of the shale oil formation in the Lucaogou Formation in the Jimsar Sag are characterized with high-pressure mercury injection (HPMI), nuclear magnetic resonance (NMR), and fractal theory. The capillary bundle model, geometric model, and wetting phase model are used to obtain the fractal dimension of the capillary pressure curve. Among them, Df1 from the capillary bundle model is between 2.1937 and 3.4131, Df2 from the geometric model is within a range of 1.0414–3.575, and Df3 from the wetting phase model is from 0.5691 to 2.7047. For NMR spectra, the pore space is divided into micropores, mesopores, and macropores based on the peak value of the NMR T2 spectra, and the fractal dimension of different pore types is calculated, where Dfmi is from 1.564 to 2.301, Dfme is in a range from 2.082 to 2.941, and Dfma is between 2.831 and 2.991. The relationships between the fractal dimension and petrophysical parameters are analyzed, and the results indicate that among the three types of models, the fractal dimension of the capillary bundle model has the highest correlation with the core petrophysical parameters. Therefore, it is recommended to use the capillary bundle model to evaluate the fractal characteristics of pore structures. In particular, the fractal dimension is positively correlated with the throat coefficient and negatively correlated with the size of the pore throat. In contrast, the fractal dimension of NMR has a poor correlation with core petrophysical parameters. There is no obvious correlation between the fractal dimension of micropores and petrophysical parameters, while the fractal dimension of mesopores and macropores is only correlated with the throat-sorting coefficient, and the correlation coefficient is less than 0.15. Thus, the fractal dimension from NMR data is not suitable for studying the fractal characteristics of shale oil cores in the Lucaogou Formation. In addition, we predicted the permeability of shale cores using the Swanson model, Pittman model, and Winland model. The permeability prediction results show that the Swanson model has the greatest accuracy, followed by the Winland model. Among them, the accuracy index (ACI) of the Swanson model is 0.901, and the ACI of the Winland model is between 0.483 and 0.897. The permeability prediction by the Pittman model is poorest among these three models.

A novel prewetting behavior of water adsorbed on solid surfaces modified with tethered chains resulting from a density functional theory

The density functional approach for classical associating fluids is used to explore wetting phase diagrams for model systems consisting of water and graphite-like solid surfaces chemically modified by a small amount of grafted chain molecules. The water-like fluid model is adopted from the work of Clark et al. [Molec. Phys. 104, 3561 (2006)]. It describes the bulk water vapor–liquid coexistence very well. Each chain molecule consists of tangentially bonded hard spheres. We focus on the investigation of the growth of water film on such a complex substrate and the construction of the wetting phase diagram. We have found that the topology of the phase diagram depends on the amount of grafted chains and on the length of chains. At low grafting densities and for short chains, the prewetting phase diagrams are similar to the diagrams for water on a non-modified solid surface. For higher grafting densities and for longer chains, the prewetting line can split into two lines that join at a triple point. Each of the lines is associated with changes in the predominant configuration of segments of grafted chains. They can either stretch or coil upon the growth of an adsorbed film. Trends of the behavior of wetting temperature and the critical temperatures of the branches of the prewetting transition are discussed.

Study on the Causes of Water Blocking Damage and Its Solutions in Gas Reservoirs with Microfluidic Technology

The water blocking damage to the reservoir caused by the invasion of external fluid is one of the main factors that affect the efficient development of tight sandstone gas reservoirs. In this paper, microfluidic chip technology is used to explore the causes of water blocking damage in porous media and find suitable recovery solutions. The research results show that reducing the gas-liquid capillary pressure can effectively reduce the rate and quantity of spontaneous speed of cores. After chemical treatment, the liquid phase fluidity of the non-fractured matrix core is increased by 1.72 times, and that of the fractured core is increased by 2.13 times. In water wetting porous media, there are mainly four types of liquid hold-up: (1) Liquid hold-up in the dead volume of a non-connected pore; (2) The water phase in the pore throat with a small inner diameter cannot be driven away due to its larger capillary pressure; (3) Adsorption viscous force, the wetting phase is adsorbed on the surface of the solid phase; (4) Reservoir heterogeneity. The water blocking damage can be removed to a certain extent by changing the gas injection pressure, the gas injection method, or adding a wetting modifier.

Stimulating relative permeability changes by low-frequency elastic waves: Theory and lab experiments

A model is presented to describe how low-frequency vibrations can induce changes to relative permeabilities in dual-porosity dual-permeability rocks. We show that a combination of two physical processes may cause this effect: 1) the wave-induced two-phase fluid flow between soft pores (fractures or cracks) and stiff pores (matrix); and 2) the contact angle hysteresis effect. These two effects lead to redistribution of fluid saturation between fractures and matrix, which may explain alteration of relative permeabilities by small transient strains (∼10−6) in rocks where the fluid flow occurs primarily through the fracture network, and fluid storage occurs predominantly in the porous matrix. We assume that the frequency is low enough that viscous and inertial effects are negligible and that any stress-induced increments of pore pressure are uniform within wetting and nonwetting fluid phases. We demonstrate that pulse-like vibrations are much more efficient in changing relative permeabilities than sinusoidal-shaped vibrations. Furthermore, we show that two waveforms with the same amplitude and frequency but with different polarities could have opposite effects on the alteration of relative permeabilities. Specifically, extensional pulses increase oil relative permeability and decrease water relative permeability in the water-wet rock. Contrary, compressional pulses decrease oil relative permeability and increase water relative permeability in the water-wet rock. To validate theoretical results, we developed a unique low-frequency laboratory setup and experimental methods. We performed drainage and imbibition cycles on a sandstone sample using oil and water as pore fluids. During flooding, the sample was excited by small-strain seismic pulses of a specific shape, with varying polarization direction, frequency, and amplitude. The preliminary laboratory results validate the theoretical model qualitatively. The proposed model may contribute to environmentally friendly and low-cost methods for stimulating hydrocarbon production in conventional reservoirs without invasive chemicals or fracking. In unconventional reservoirs, however, this technology can be envisioned as supplementary to standard EOR/IOR techniques. Normally, the seismic wave energy is too low to increase absolute permeability or decrease oil viscosity; only relative permeabilities can be affected.

Opposite Atlantic Multidecadal Oscillation effects on dry/wet changes over Central and East Asian drylands

The Central Asian dryland (CAD) and East Asian dryland (EAD) are typical drylands in the globe. They are characterized by less precipitation, with vulnerable and sensitive ecosystems. Although they are located in the heart of continent, precipitation in these regions has opposite patterns on the multi-decadal time scale. In this study, we focus on different responses of precipitation changes in these drylands and related drought to different phases of the Atlantic Multidecadal Oscillation (AMO) on the multi-decadal time scale. We show that less precipitation in the CAD and more precipitation in the EAD were always associated with a positive AMO phase, which was caused by the weakened westerly and simultaneous enhancement of vertically integrated water vapor from the Indian Ocean and western Pacific. Such precipitation pattern was accompanied by a drying (wetting) phase of self-calibrating Palmer's drought severity index in the CAD (EAD), which further contributed to a worse (better) ecology in the CAD (EAD). This explains why the positive AMO phase in recent decades starting from 2000 made a positive contribution to the drying (wetting) arid region in the CAD (EAD).