Simulation of viscous instabilities in miscible and immiscible displacement

This study includes modeling of viscous instabilities at both miscible and immiscible displacement. Oil recovery of heavy oil leads to unstable displacement for adverse mobility ratio for both miscible and immiscible displacement. Simulation studies of viscous fingering in miscible and immiscible displacements were performed in order to history match 2D slab laboratory experiments performed at CIPR, Centre for Integrated Petroleum Research. History matching of a polymer flood experiment is also included in this thesis. All simulations were performed using UTCHEM, a chemical flooding simulator developed at the University of Texas at Austin. In the laboratory experiment, viscous fingering was observed for the miscible displacement at unfavorable mobility ratio. For the miscible displacement at favorable mobility ratio, an indifferent displacement process (more piston-like displacement) was observed. For the immiscible displacements, both at unfavorable mobility ratio, viscous fingering was only observed in the case with zero initial water saturation. The presence of capillary pressure, however, smeared out the front of the fingers, turning the displacement process indifferent over time. At unfavorable mobility ratio, a water flood experiment was followed by a polymer flood. During the polymer flood an oil bank was accumulated, and considerable additional oil was produced. To history match the miscible displacement an approach was tried by using variation in local grid block permeability. This approach with large variation in permeability field, miscible displacement showed overall good agreement with the experimental results. The miscible displacement at favorable mobility ratio, when simulated in UTCHEM, showed an indifferent type displacement process. The simulation model of the miscible displacement at unfavorable mobility ratio, showed the formation of viscous fingering very similar to that obtained in the laboratory experiment. The applied method of permeability distribution seems to match both displacements at favorable and unfavorable mobility ratio. The simulated model for immiscible displacement at Swi=0, did not generate viscous fingers. The establishment of water films is most likely a fast kinetic reaction that is not included in the simulator and is therefore not observed in UTCHEM. The UTCHEM simulator did, however, provide similar results for the immiscible displacement at Swi=0.12. The applied capillary pressure in the immiscible displacements causes smearing of the front, which results in an indifferent type displacement. The simulation model of the polymer flood following a water flood showed the accumulation of an oil bank very similar to observed experimental results. In order to match the oil bank formation and oil recovery by polymer flooding, the residual oil saturation in the simulation model had to be reduced from the residual oil saturation by water flooding (Sor,w=0.47), to a lower residual oil saturation after polymer flooding (Sor,p=0.31). The approach of only changing endpoint saturations and including the physical chemistry properties of the polymers, was able to give a good history match of the experiment.MAMN-PETKJPETRRESK

Effect of a Pore Throat Microstructure on Miscible CO2 Soaking Alternating Gas Flooding of Tight Sandstone Reservoirs

Miscible CO2 soaking alternating gas (CO2-SAG) flooding is an improved version of CO2 flooding, which compensates for the insufficient interaction of CO2 and crude oil in the reservoir by adding a CO2 soaking process after the CO2 breakthrough (BT). The transmission of CO2 in the reservoir during the soaking process is controlled by the pore throat structure of the formation, which in turn affects the displacement efficiency of the subsequent secondary CO2 flooding. In this work, CO2-SAG flooding experiments at reservoir conditions (up to 70 °C, 18 MPa) have been carried out on four samples with very similar permeabilities but significantly different pore size distributions and pore throat structures. The results have been compared with the results of CO2 flooding on the same samples. It was found that the oil recovery factors (RFs) when using CO2-SAG flooding are higher than those when using CO2 flooding by 8–14%. In addition, we find greater improvements in the RF for rocks with greater heterogeneity of their pore throat microstructure compared with CO2 flooding. The CO2 soaking process compensates effectively for the insufficient interaction between CO2 and crude oil because of premature CO2 BT in heterogeneous cores. Moreover, rocks with a more homogeneous pore throat microstructure exhibit a higher pressure decay rate in the CO2 soaking process. The initial rapid pressure decay stage lasts for 80–135 min (in our experimental cores), accounting for over 80% of the total decay pressure. Rocks with the larger and more homogeneous pore throat microstructure exhibit smaller permeability decreases because of asphaltene precipitation after CO2-SAG flooding, possibly because the permeability of rocks with a more heterogeneous and smaller pore throat microstructure is more susceptible to damage from asphaltene precipitation. However, the overall permeability decline is 0.6–3.6% higher than that of normal CO2 flooding because of the increased time for asphaltene precipitation. Nevertheless, the corresponding permeability average decline per 1% oil RF is 0.11–0.34%, which is lower than that for CO2 flooding, making the process worthwhile. We have shown that CO2-SAG flooding has the potential to improve oil RFs with relatively less damage to cores, especially for cores with small and heterogeneous pore throat microstructures, but for which severe wettability changes due to the CO2 soaking process can become significant

Effect of Pore-Throat Microstructures on Formation Damage during Miscible CO2 Flooding of Tight Sandstone Reservoirs

Pore and throat blockage and wettability alteration caused by asphaltene deposition are serious problems during the injection of CO2 into subsurface reservoirs for enhanced oil recovery (EOR). During miscible CO2 flooding, the efficacy and distribution of fluid flow in sandstone reservoirs are controlled by the pore-throat microstructure of the rock. Furthermore, CO2 injection promotes asphaltene precipitation on pore surfaces and in the pore throats, decreasing the permeability and altering reservoir wettability. In this work, miscible CO2 flooding experiments under reservoir conditions (up to 70 ± 0.1 °C, 18 MPa) were carried out on four samples with very similar permeabilities but significantly different pore size distributions and pore-throat structures to study the effects of the pore-throat microstructure on formation damage. The features of the pore-throat structure were evaluated by fractal theory, based on constant-rate mercury intrusion (CRMI) tests. Reservoir rocks with smaller pore-throat sizes and more heterogeneous and poorer pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding 14–22% lower oil recovery factors (RFs) and 4–7% greater decreases in permeability compared to more homogeneous rocks and rocks with larger pore throats. However, the water-wettability index of cores with larger and more connected pore-throat microstructures was found to drop by an extra 15–25% compared to the water-wettability decrease found for heterogeneous cores. We attribute these observations to an increase in asphaltene precipitation caused by the larger sweep volume of injected CO2, which occurs in rocks with larger and more homogeneous pore throats. In addition, we observed that rocks with more homogeneous pore-throat microstructures also exhibit homogeneity in the consequent distribution of formation damage

Numerical study of Bingham flow in macrosopic two dimensional heterogenous porous media

The flow of non-Newtonian fluids is ubiquitous in many applications in the geological and industrial context. We focus here on yield stress fluids (YSF), i.e. a material that requires minimal stress to flow. We study numerically the flow of yield stress fluids in 2D porous media on a macroscopic scale in the presence of local heterogeneities. As with the microscopic problem, heterogeneities are of crucial importance because some regions will flow more easily than others. As a result, the flow is characterized by preferential flow paths with fractal features. These fractal properties are characterized by different scale exponents that will be determined and analyzed. One of the salient features of these results is that these exponents seem to be independent of the amplitude of heterogeneities for a log-normal distribution. In addition, these exponents appear to differ from those at the microscopic level, illustrating the fact that, although similar, the two scales are governed by different sets of equations

Effect of viscosity and heterogeneity on dispersion in porous media during miscible flooding processes

In this paper, a mathematical model has been developed to quantitatively examine the effect of viscosity and heterogeneity on dispersion in porous media at the pore scale during miscible flooding processes. More specifically, the Navier-Stokes equation and advection-diffusion equation are coupled with supplementary equations to describe the solvent transport behaviour. Two-dimensional heterogeneous models are numerically developed as a function of porosity and permeability, assuming that the grain sizes satisfy normal distribution. In addition, the performance of miscible hydrocarbon gas injection in heterogeneous porous media is comprehensively evaluated. It is found that a larger aspect ratio (ratio of pore throat size) in the single non-flowing pore model results in a greater asymmetry of the concentration curve. As for single non-flowing pore models and heterogeneous models, the dispersion coefficients increase with the expansion of the non-flowing domain. Both the heterogeneity of porous media and the variable viscosity of th fluid mixture contribute to the asymmetry of the concentration curve in the heterogeneous model. A negative correlation is established between the sorting coefficients of pore throat size and the power-law coefficients. As for slug injection, the injected solvent slug size along the longitudinal direction does not effectively influence the longitudinal length of the mixing zone for a given porous medium and fluids, though the Peclet number and the porosity greatly affect the length and concentration distribution of the mixing zone.Cited as: Bai, Z., Song, K., Fu, H., Shi, Y., Liu, Y., Chen, Z. Effect of viscosity and heterogeneity on dispersion in porous media during miscible flooding processes. Advances in Geo-Energy Research, 2022, 6(6): 460-471. https://doi.org/10.46690/ager.2022.06.0

Tracing back the source of contamination

From the time a contaminant is detected in an observation well, the question of where and when the contaminant was introduced in the aquifer needs an answer. Many techniques have been proposed to answer this question, but virtually all of them assume that the aquifer and its dynamics are perfectly known. This work discusses a new approach for the simultaneous identification of the contaminant source location and the spatial variability of hydraulic conductivity in an aquifer which has been validated on synthetic and laboratory experiments and which is in the process of being validated on a real aquifer

Viscous fingering with partially miscible fluids

Viscous fingering—the fluid-mechanical instability that takes place when a low-viscosity fluid displaces a high-viscosity fluid—has traditionally been studied under either fully miscible or fully immiscible fluid systems. Here we study the impact of partial miscibility (a common occurrence in practice) on the fingering dynamics. Through a careful design of the thermodynamic free energy of a binary mixture, we develop a phase-field model of fluid-fluid displacements in a Hele-Shaw cell for the general case in which the two fluids have limited (but nonzero) solubility into one another. We show, by means of high-resolution numerical simulations, that partial miscibility exerts a powerful control on the degree of fingering: fluid dissolution hinders fingering while fluid exsolution enhances fingering. We also show that, as a result of the interplay between compositional exchange and the hydrodynamic pattern-forming process, stronger fingering promotes the system to approach thermodynamic equilibrium more quickly

Solute transport in layered and heterogeneous soils

Better understanding of transport of dissolved chemicals in soils and aquifers is important to evaluate and remediate contaminated soils and aquifers. Because of the nature of heterogeneity of field porous media, studies on transport processes in non-homogeneous media are necessary. In this study, transport of solutes in layered and heterogeneous media was investigated using numerical approximations. For layered soils, transport properties were assumed homogeneous within individual layers but different between layers. For heterogeneous systems, either a time-dependent or distance-dependent dispersivity was considered to represent the effects of heterogeneity. In a series of simulations of transport in two-layered soils, we found that breakthrough curves (BTCs) were similar regardless of the layering sequence for all reversible and irreversible solute retention mechanisms. Such findings were in agreement with results from laboratory experiments using tritium as a tracer and Ca and Mg as reactive solutes. Field measured apparent dispersivity is often found to increase with time because of the heterogeneity of soils and aquifers. We proposed a fractal model to explain the time dependency of dispersivity. Our model indicates a nonlinear increase of variance of travel distance with time or mean travel distance, which implies a time-dependent dispersivity. Application of our model to three field experiments (the Cape Cod, the Borden, and the Columbus sites) indicates fractal behavior for all three cases. The term scale effects is often used in the literature to refer to the dependency of dispersivity on either mean travel distance or distance from source. We presented a critical review on the ambiguity in definition of this term. We presented comparisons between transport processes in systems with time-dependent and distance-dependent dispersivities. Our results showed that enhanced spreading in BTCs consistently occurred in systems with time-dependent dispersivities. Recently, a new governing equation, factional-order advection-dispersion equation (FADE) was proposed to describe transport processes in heterogeneous systems. We proposed a statistical method to justify the use of a FADE. A fractional order of 1.82 was confirmed to be necessary to describe the bromide plumes at the Cape Cod site