Multi-component lattice Boltzmann models for accurate simulation of flows with wide viscosity variation

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In some of the challenging digital rock applications the trade-off between model resolution and representative elemental volume is not captured in a single resolution model satisfying the minimum requirements for both aspects. In the wide range of lithofacies found in carbonate reservoir rocks, some facies fall in this category, where large pores, ooids or vugs, are connected by small scale porous structures that could have orders of magnitude smaller pores. In these cases a multi-scale digital rock approach is needed. We recently developed an extension to a digital rock workflow that includes a way to handle sub-resolution pore structures in single phase and multi-phase flow scenarios in addition to regular resolvable pore structures. Here we present an application of this methodology to a multi-scale limestone carbonate rock. A microCT image captures the large pores for this sample, but does not resolve all the pores smaller than the pixel size. A three phase image segmentation that considers pore, solid and under-resolved pores or porous media (PM) is generated. A high resolution confocal image model is obtained for a representative region of the smaller pores or PM region. A set of constitutive relationships (namely permeability vs. porosity, capillary pressure vs saturation and relative permeability vs saturation) are obtained by simulation from the high resolution confocal model. The low resolution segmented image, a porosity distribution image, and the constitutive relationships for the PM are input in an extended LBM multi-scale multi-phase solver. First we present results for absolute permeability and show a parametric study on PM permeability. The model recovers the expected behaviour when the PM regions are considered pore or solid. A consistent value of permeability with experiments is obtained when we use the PM permeability from the high resolution model. To demonstrate the multi-phase behaviour, we present results for capillary pressure imbibition multi-scale simulations. Here a small model for a dual porosity system is created in order to compare single scale results with the multi-scale solver. Finally, capillary imbibition results for the whole domain are shown and different wettability scenario results are discussed. This application illustrates a novel multi-scale simulation approach that can address a long standing problem in digital rock.

Section: Multi-scale Modellingmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Multi-scale Digital Rock: Application of a multi-scale multi-phase workflow to a Carbonate reservoir rock

Fager

Otomo²,

Salazar-Tio³

et al. 2023

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“…This solver has been validated on a variety of fundamental benchmarks and real reservoir rock test cases [23][24][25][26][27][28]. It also includes the ability to deal with high viscosity ratio of the immiscible fluid phases [29].…”

Section: Multiphase Numerical Simulationmentioning

confidence: 99%

Pore-scale Analysis of CO₂-brine Displacement in Berea Sandstone and Its Implications to CO₂ Injectivity

Sun

Fager

et al. 2023

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For storage in deep saline formations, where CO2 is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO2 injectivity is considered to reach the maximum value at the CO2 endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO2-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO2-brine flow in the sample of Berea sandstone. CO2/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO2 storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO2 displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO2 injectivity. The result shows that water-wet condition facilitates the CO2 injection when there is no fracture induced.

“…In order to capture correctly the physics of multicomponent fluid flow, even at low resolution, the current LBM implementation uses, in addition to the voxel elements, triangulated surface elements also known as surfels, to accurately capture the pore-grain boundary as demonstrated in [35][36][37]. The use of surfels to define the exact wall location results in more accurate fluxes near boundaries, and increased accuracy at lower numerical resolution compared with operating directly on the voxel grid of the micro-CT scan.…”

Section: Numerical Modelling Approachmentioning

confidence: 99%

Digital rock workflow to calculate wettability distribution in a reservoir rock

Islam

Salazar²,

Crouse³

2023

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Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations.