Porous Flow of Energy & CO₂ Transformation and Storage in Deep Formations

CO₂-brine relative permeability significantly impacts CO₂ injection and is a key parameter for carbon dioxide storage simulation in saline aquifers. In the study of relative permeability, factors such as temperature, pressure, and reservoir rock physical properties play a crucial role. To better understand the impact of confining pressure on the CO₂-brine relative permeability characteristics of sandstone in the Ordos Basin, five sets of CO₂-brine relative permeability data were obtained through unsteady-state displacement tests conducted at various confining pressures ranging from 12 to 20 MPa. The research findings indicate that with an increase in confining pressure there is a slight decrease in irreducible brine saturation. Furthermore, the CO₂ relative permeability in the irreducible brine state decreased by 57% as the pressure increased from 12 MPa to 20 MPa. The study demonstrates notable differences in the CO₂-brine relative permeability curves under varying confining pressure conditions. As the confining pressure increases, the CO₂ relative permeability curve decreases, while the brine relative permeability increases. The change in brine relative permeability is not as pronounced as that of CO₂. These experimental results offer essential support for subsequent numerical calculations and practical applications in engineering. Experimental research holds significant importance in the assessment of storage potential and the prediction of the evolutionary patterns of CO₂ migration. Full article

Low-permeability sandstone reservoirs have been widely used as a gas storage medium worldwide. Compared with the high porosity and high permeability of sandstone, low-permeability sandstone may present different mechanical (deformation, damage or failure) and acoustic responses under cyclic loading-unloading processes caused by the high-rate injection–production of underground gas storage. In this paper, multistage triaxial loading–unloading tests with a continuously increased upper limit of stress were carried out on low-permeability sandstone under six different confining pressures. The results showed that the superposition of stress–strain curves become much denser in the process of each level of stress. Based on the variation of the elastic modulus of low-permeability sandstone under alternating loads, the mechanical behavior of low-permeability sandstone under cyclic loading is divided into three stages: cyclic hardening, stability and cyclic softening. According to the evolution of acoustic emission (AE) signal parameters, AE counts appear intensively at the initial stage of each level of stress and then gradually stabilize. The peak frequency presents the zonal distribution, which is divided into low-frequency, intermediate-frequency and high-frequency zones. Low confining pressure leads to a small b-value. The RA–AF distribution implies that the mixed tensile–shear cracks are continuously generated in low-permeability sandstone during the cyclic loading process, and the shear cracks are more obviously developed. Full article

The low-permeability reservoirs have abundant reserves and broad development prospects, and the supplementary energy methods have gradually become a hot research topic. In addition, the technology of enhanced oil recovery through supercritical CO₂ injection is becoming increasingly mature; however, the changes in reservoir properties at the microscopic level still need further investigation. In this study, natural rock cores from low-permeability reservoirs were used to simulate reservoir conditions and conduct supercritical CO₂ injection experiments for energy supplementation. The study aimed to investigate the changes in reservoir microstructure, minerals, and crude oil properties before and after the experiments. The research results indicate that after supercritical CO₂ injection into the reservoir, it dissolves in the formation water to form carbonic acid. Under the effect of dissolution, the porosity of the low-permeability reservoir increases by 1.06–5.68%, and permeability can be improved by 40–60%. The rock becomes more water-wet and less oil-wet. The content of calcite and feldspar in the rock minerals decreases due to the dissolution of carbonic acid, resulting in a reduction in plagioclase and calcite. After the CO₂ injection, the light components (C₈–C₁₀) in the crude oil in the rock cores decreased by approximately 14.6%, while the heavy components (C₁₆–C₃₉) increased by 6.99%. The viscosity of the crude oil decreases, and its flowability is further enhanced. Full article

Layered rock mass is a common rock mass structure with diverse forms and complex mechanical properties. Three types of composite layered rock mass prepared using sandstone and shale can be divided into sandwiched type, interbedded type and superimposed type. The total height of the combined rock mass is 50 mm, which is a cylinder composed of sandstone and shale with a diameter of 25 mm and different thickness. Uniaxial compression tests on sandstone, shale and combined rock mass were performed. The results show that, with the increase in the content of soft components, the compressive strength and elastic modulus of the combined rock mass tend to decrease. The mechanical properties of the superimposed rock mass will be between the two components and close to the soft component in numerical value. The mechanical properties of sandwiched rock mass are obviously affected by the properties of the sandwiched rock. When the content of the components is consistent, interbedded rock mass often shows higher strength and elastic modulus. Compared with other rock mass, interbedded rock mass has more stable mechanical properties. The stress–strain curve can be divided into the compaction stage, elastic stage, plastic development stage and post-fracture stage. The composition content of the rock mass plays a decisive role in the compaction stage. The failure modes are mainly shear failure and tensile failure. With the increase in soft rock content, the failure degree of soft rock is gradually weakened, and the failure modes show a trend from tensile failure to shear failure. The experimental results provide theorical guidance for underground engineering construction. Full article

The accurate description of micro-/nanopores in deep coal reservoirs plays an important role in evaluating the reservoir properties and gas production capacity of coalbed methane (CBM). This work studies nine continuous samples of high–rank coal from the Daning–Jixian area of the Ordos Basin. Maceral analysis, proximate analysis, field emission scanning electron microscopy (FE-SEM), low-pressure CO₂ adsorption (LPA), low-temperature N₂ adsorption (LTA) and high-pressure methane adsorption (HPMA) experiments were conducted for each sample. The fractal dimension (D) of the LPA data was calculated by using the micropore fractal model. The characteristics of the deep coal reservoir pore structure, proximate analysis, relationship between maceral and fractal dimensions, and gas adsorption capacity of the micropores are discussed. The results showed that the combination of LPA with nonlocalized density functional theory (NLDFT) models and LTA with NLDFT models can more accurately determine the pore size distribution of the micropores. The pore volume (PV) and specific surface area (SSA) of the coals were distributed in the ranges of 0.059~0.086 cm³/g and 204.38~282.42 m²/g, respectively. Although the degree of micropore development varies greatly among different coal samples, the pore distribution characteristics are basically the same, and the PV and SSA are the most developed in the pore size range of 0.4–0.7 nm. Ash content (A_d) and mineral composition are two major factors affecting micropore structure, but they have different impacts on the fractal dimension. The higher the vitrinite content, moisture content (M_ad) and Ad are, the larger the micropore fractal dimension (D) and the stronger the heterogeneity of the pore structure. Micropores account for 99% of the total SSA in coal, and most methane can be adsorbed in micropores. The fractal dimension of micropores can be used to evaluate the pore structure characteristics. The larger the fractal dimension, the smaller the micro-SSA and micro-PV of the coal sample. Fractal analysis is helpful to better understand the pore structure and adsorption capacity of CBM reservoirs. Full article

A deep understanding of the pore-scale fluid flow mechanism during the CO₂ flooding process is essential to enhanced oil recovery (EOR) and subsurface CO₂ sequestration. Two-phase flow simulations were performed to simulate the CO₂ flooding process based on the phase-field method in this study. Two-dimensional models with random positions and sizes of grains of circular shape were constructed to reproduce the topology of porous media with heterogeneous pore size distributions in the reservoir rock. A multiple-parameter analysis was performed to investigate the effects of capillary number, viscosity ratio, wettability, density, gravity, interfacial tension, and absolute permeability on the two-phase fluid flow characteristics. The results indicated that when the capillary number and viscosity ratio were large enough, i.e., log Ca = −3.62 and log M = −1.00, the fingering phenomenon was not obvious, which could be regarded as a stable displacement process. CO₂ saturation increased with the increase in the PV value of the injected CO₂. Once the injected CO₂ broke through at the outlet, the oil recovery efficiency approached stability. Two types of broken behaviors of the fluids were observed during the wettability alternation, i.e., snap-off and viscous breakup. Snap-off occurred when capillary forces dominated the fluid flow process, while viscous breakup occurred with a low viscosity ratio. With a low capillary number, the flooding process of the injected CO₂ was mainly controlled by the capillary force and gravity. With the decrease in the interfacial tension between the fluids and the increase in the permeability of the porous media, the recovery of the displaced phase could be enhanced effectively. In the mixed-wet model, with the increase in the percentage of the nonoil-wetted grains, the intersecting point of the relative permeability curve moved to the right and led to a higher oil recovery. Full article

A deep understanding of the dissociation and transportation mechanism of natural gas hydrate (NGH), taking into account the effects of geo-stress, contributes to optimizing the development strategy and increases the exploitation efficiency of NGH. In this paper, the mathematical model, coupled with fluid heat and mass transfer, multiphase flow mechanics, and reaction kinetics with phase change in the process of hydrate decomposition was established. An axisymmetric two-dimensional model was developed to simulate the depressurization decomposition process of natural gas hydrate in the Berea sandstones. FLUENT software was used to solve the fundamental governing equations of the multi-phase flow, and UDF programming was employed to program the hydrate decomposition model and the modified permeability model in the dissociation and transportation of NGH. The simulation results were then validated by Masuda’s experimental data. The effects of gas saturation, outlet pressure, temperature, absolute permeability and geo-stress on the decomposition of natural gas hydrate were studied. The results indicated that a higher absolute permeability, higher initial gas saturation, lower outlet pressure, and higher initial temperature advance the decomposition rate of hydrate. Thus, an optimized production plan is essential to promote the extraction efficiency of the NGH. The geo-stress causes a decrease in the porosity and permeability of the porous rock, which restricts the efficiency of the heat and mass transfer by the fluid flow, leading to a slower dissociation and transportation rate of the NGH. Thus, it is important to take geo-stress into consideration and balance the extracting efficiency and the well pressure, especially when the NGH is developed by depressurization. Full article

Due to the complexity of the sedimentary and diagenetic processes, natural rocks generally exhibit strong heterogeneity in mineral composition, physicochemical properties, and pore structure. Currently, 3D printed (3DP) rock analogs fabricated from sandy materials (silica sand) are widely applied to study the petrophysical and geomechanical characteristics of reservoir rocks, which provides an alternative and novel approach for laboratory tests to calibrate the environmental uncertainties, resolve up-scaling issues, and manufacture customized rock specimens with consistent structure and controllable petrophysical properties in a repeatable fashion. In this paper, silica sand with various grain sizes (GS) and Furan resin were used to fabricate rock analogs with different layer thicknesses (LTs) using the binder-jetting 3DP technique. A comprehensive experimental study was conducted on 3DP rock analogs, including helium porosity measurement, micro-CT scanning, SEM, and uniaxial compression. The results indicate that the LT and GS have a great influence on the physical properties, compression strength, and failure behavior of 3DP rock analogs. The porosity decreases (the difference is 7.09%) with the decrease in the LT, while the density and peak strength increase (showing a difference of 0.12 g/cm³ and 5.67 MPa). The specimens printed at the 200 and 300 μm LT mainly experience tensile shear destruction with brittle failure characteristics. The ductility of the 3DP rocks increases with the printing LT. The higher the content of the coarse grain (CG), the larger the density and the lower the porosity of the specimens (showing a difference of 0.16 g/cm³ and 8.8%). The largest peak compression strength with a mean value of 8.53 MPa was recorded in the specimens printed with CG (i.e., 100% CG), and the peak strength experiences a decrease with the increment in the content percentage of the fine grain (FG) (showing a difference of 2.01 MPa). The presented work helps to clarify the controlling factors of the printing process and materials characteristics on the physical and mechanical properties of the 3DP rock analogs, and allows for providing customizable rock analogs with more controllable properties and printing schemes for laboratory tests. Full article

Accurately predicting the critical differential pressure (CDP) of sand production contributes to improving the peak-shaving capacity and ensuring safe operation of underground gas storage (UGS). The CDP of sanding production in the target wells of the UGS was predicted coupling laboratory tests, inversed analysis with well logging data and numerical simulations. The in-situ mechanical properties of rock were estimated by coupling the laboratory test results and well-logging data. The in-situ stress field of the target formation was then deduced through inversed analysis coupled finite element method (FEM) and genetic algorithm (GA), based on the existing known stress data and the seismic data of the measured points. Using the critical strain limit (CSL) of 5‰ as the sanding criterion of the wellbore, the CDPs of the gas production in the UGS were predicted, which was 5.59 MPa, 3.98 MPa, and 4.01 MPa for well #1, well #2 and well #3, when the pressure of the gas storage was 30 MPa, respectively. The simulation results showed good agreements with the field-measured benchmark data of well #2 and well #3. The effects of moisture contents (ranging from 10 to ~40%), and cycling times of gas injection and withdrawal (ranging from 40 to ~200 cycling times) on the critical differential pressure were simulated and analyzed. The results indicated that the CDP decreased with an increase of the moisture content and the cycling times. This study provides a reliable tool for the sanding prediction of the wellbore in the UGS. Full article

It is very important to effectively describe the sweep characteristics of CO₂ miscible flooding based on physical models for actual reservoir development. In this study, based on the geological characteristics of the Jilin ultra-low permeability reservoir, which has significant vertical heterogeneity, a two-dimensional double-layer heterogeneous visualization model with a permeability contrast of 10 and thickness contrast of 2 was designed to perform experimental research on the sweep law of CO₂ miscible flooding with an injection-production mode of “united injection and single production”. With the goal of determining the obvious differences in the gas absorption capacity and displacement power of the two layers, the CO₂ dynamic miscible flooding characteristics were comprehensively analyzed, and the sweep law of CO₂ miscible flooding, including the oil and gas flow trend, migration direction of the oil–gas interface, and distribution characteristics of the miscible zone, was further studied in combination with the oil displacement effect. In this experiment, the gas absorption capacity was the key factor affecting the sweep efficiency of the CO₂ miscible flooding. Under the combined influence of the internal and external control factors of the reservoir thickness, permeability, and injection-production mode, the gas absorption capacity of the high-permeability layer was much greater than that of the low-permeability layer, resulting in the retention of a large amount of remaining oil in the low-permeability layer, which effectively displaced and swept the oil in the high-permeability layer. The gas absorption capacity of the reservoir, gravitational differentiation, and miscible mass transfer were key factors affecting the migration of the oil–gas interface and distribution of the miscible zone. The entire displacement process could be divided into three stages: ① The gas-free rapid oil production stage, which was dominated by the displacement; ② the low gas–oil ratio stable oil production stage, which was jointly affected by the displacement and miscible mass transfer; and ③ the high gas–oil ratio slow oil production stage, which was dominated by the effect of CO₂ carrying. Full article