Pore-scale simulation of shale oil flow based on pore network model

Limestone pore structure strongly influences dissolution and associated reactive transport. These effects are critical in limestone diagenesis and but also in engineering operations such as carbon capture and storage (CCS). However, detailed studies on how CO2‐enriched (acidic) brine changes this pore structure at relevant reservoir storage conditions are very limited. Thus, to provide further quantitative information and more fundamental understanding about these key processes, we studied the dissolution patterns of a homogeneous, a fractured, and a vuggy limestone when flooded with CO2‐saturated brine at representative storage conditions. The pore structured of these limestones showed drastically different responses to the acidic brine flood. As such, preferential channels surrounded by branched channels were formed in the homogeneous sample, while fractures became the main flow path in the fractured sample. In contrast, only one dominant channel formed in the vuggy sample, which resulted in a sharp permeability increase. These dissolution patterns reflect the associated Damkohler number, which significantly lower in the homogeneous, representing uniform dissolution. However, after injecting sufficient reactive fluid (1,000 PV), this uniform dissolution pattern transformed into a single preferential channel growth. Moreover, we conclude that increasing complexity of the pore geometry leads to more nonuniform dissolution. These dissolution patterns indicate the effect of initial pore structure on preferential channel growth and reaction transport. Our work provides key fundamental data for further quantifying limestone dissolution patterns in CCS, indicating that the CO2 injection may cause the reactivation of geological faults and damage around wellbore, thus aids in the implementation of industrial‐scale CCS.

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Dynamic Pore‐Scale Dissolution by CO 2 ‐Saturated Brine in Carbonates: Impact of Homogeneous Versus Fractured Versus Vuggy Pore Structure

Stress Sensitivity of Fractured and Vuggy Carbonate: An X-Ray Computed Tomography Analysis

Hypothesis Low salinity surfactant nanofluids have recently shown promising characteristics in wettability alteration of the silicate-based rock representative substrate and interfacial tension reduction of oil/aqueous phase interface. Pore level understanding of the physical processes entailed in this new class of low salinity injection fluids in oil-phase saturated real rock porous media is required, which has not been conceived yet. Experiments Thus, we investigate the oil recovery performance and possible mechanisms of oil recovery by the injection of low salinity surfactant (SDBS, 1.435 mM) aqueous solutions (with 0%, 0.01% and 0.1% (by weight) ZrO2 nanoparticles) into the oil phase saturated Doddington sandstone miniature core plugs. The designed experiment involves core flooding with X-ray transparent core-holder developed in-house and analysis/processing of the acquired image data. Findings The injection of low salinity surfactant nanofluids with 0.01% ZrO2 nanoparticles leads to maximum oil phase recovery. The results suggest that the dominating mechanisms for oil recovery are wettability alteration, inherent interfacial tension reduction, and the effect of significant amount of microemulsions formation is rather trivial. Low salinity effect, even in combination with surfactant, caused fines migrations (not reported earlier), is found to be significantly mitigated using nanoparticles. This new class of fluids may significantly enhance oil recovery.

Pore scale investigation of low salinity surfactant nanofluid injection into oil saturated sandstone via X-ray micro-tomography

The pore size distribution (PSD) and fractal dimension of tight sandstone are studied with mercury intrusion porosimetry (MIP). Four different fractal models are used to calculate fractal dimensions from mercury intrusion capillary pressure (MICP) and mercury extrusion capillary pressure (MECP) respectively, and the physical meanings of the fractal dimensions calculated from different fractal models are discussed. The fractal characteristics of tight sandstone pore spaces with unimodal and bimodal PSD are compared. The correlations between fractal dimensions and tight sandstone petrophysical properties are researched, and the optimal fractal model for formation evaluation is recommended. Finally, the key parameters influencing tight sandstone permeability are investigated.

Analysis of pore size distribution and fractal dimension in tight sandstone with mercury intrusion porosimetry

To investigate the characteristics of oil distribution in porous media systems during a high water-cut stage, sandstones with different permeability scales of 53.63 ×10-3 μm 2 and 108.11 ×10-3 μm 2 were imaged under a resolution of 4.12 μm during a water flooding process using X-ray tomography. Based on the cluster-size distribution of oil segmented from the tomography images, and through classification using the shape factor and Euler number, the transformation of the oil distribution pattern in different injection stages was studied for samples with different pore structures. In general, the distribution patterns of an oil cluster continuously change during water injection. Large connected oil clusters break off into smaller segments. For sandstones with higher permeability, which show the largest change in distribution pattern, and the remaining oil is trapped in the pores with a radius of approximately 7-12 μm. Meanwhile, some disconnected clusters merge and lead to a re-connection during the high water cut period. Whereas the pore structure becomes compact and complex, the residual non-wetting phase becomes static and is difficult to move, and thus all distribution patterns coexist during the entire displacement process, and are mainly distributed in pores with a radius of 8-12 μm. For the pore-scale entrapment characteristics of the oil phase during a high water cut period, different enhance oil recovery (EOR) methods should be considered in sandstones correspondent to each permeability scale.

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Microscopic Determination of Remaining Oil Distribution in Sandstones With Different Permeability Scales Using Computed Tomography Scanning

Changes in relative permeability curves for natural gas hydrate decomposition due to particle migration

Polymer flooding is an important tertiary recovery method. However, even after its application, more than 50% of the oil remains in the formation layers. It is thus important for efficient resource...

Quantitative Statistical Evaluation of Micro Residual Oil after Polymer Flooding Based on X-ray Micro Computed-Tomography Scanning

The invention discloses a porous medium contact angle determining method and system. The determining method comprises the following steps of in a displacement simulation experiment, injecting displacement fluid into a real rock core and performing computed tomography (CT) on the rock core at different practical oil outlet time periods to determine three-dimensional images at different moments; dividing different phases of the three-dimensional images and determining the divided three-dimensional images; marking contact lines among different phases according to the divided three-dimensional images, wherein the phases are underground fluid or the displacement fluid and rock frameworks in the displacement simulation experiment; determining the contact angle of porous media in different positions at different moments according to the contact lines. The contact angle dynamic change process in different positions in the rock core and at different displacement moments can be obtained by usingthe determining method and system provided by the invention; the wettability of the real oil reservoir environment can be more accurately reflected; a foundation is provided for oil-gas field development so as to greatly increase the yield.

Liu Tao

Papers

Stress Sensitivity of Fractured and Vuggy Carbonate: An X-Ray Computed Tomography Analysis

Microscopic Determination of Remaining Oil Distribution in Sandstones With Different Permeability Scales Using Computed Tomography Scanning

Changes in relative permeability curves for natural gas hydrate decomposition due to particle migration

Quantitative Statistical Evaluation of Micro Residual Oil after Polymer Flooding Based on X-ray Micro Computed-Tomography Scanning

Porous medium contact angle determining method and system