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.

During microbial-enhanced oil recovery (MEOR), surfactant-producing microorganisms are reported to improve displacement efficiency. However, the sweep efficiency could be improved by emulsified droplets or be reduced by low-IFT (interfacial tension)-induced fingering flow. Therefore, whether sweep efficiency can be improved by surfactant-producing microorganisms is currently unclear. To reveal the EOR mechanisms by surfactant-producing microorganisms, a 2D micro-model was used to conduct a long-term pore-scale experiment. In the results, 19.4% of the original oil in place (OOIP) was recovered, and surfactant-producing microorganisms can improve not only displacement efficiency (16.9% of the OOIP in the main stream) but also sweep efficiency (27.7% of the OOIP in the margin). Furthermore, the sweep efficiency was improved during flooding and shut-in periods. For instance, 19.5% of the OOIP in margins migrated to the main stream during the 1st shut-in period. Regarding mechanisms of sweep, it was improved by Jamin’s effect during the flooding period, while during the shut-in period, the oil migration was attributed to the spontaneously spreading biomass and their wettability altering the biosurfactant. This long-term experiment revealed that the dominant oil recovery mechanisms were altering with declining oil saturation, based on which sweep efficiency contributed to oil recovery only at oil saturation higher than 40.5%. While at lower oil saturation, only displacement efficiency could be improved.

In this paper, based on the gneiss outcrop of Bozhong 196 gas field in China, uniaxial compression and Brazil splitting tests were conducted by using cores of different orientations. The following compression properties were studied: the elastic compression modulus, Poisson’s ratio and compressive strength of the gneiss outcrop. The following tensile properties were studied: the tensile modulus, the tensile strength and peak energy rate of gneiss outcrop. The results demonstrate the following: (1) The elastic compression modulus, compressive strength, tensile strength and peak energy rate of gneiss specimens with horizontal core-taking are greater than those with vertical core-taking. (2) The elastic compression modulus, Poisson’s ratio and compressive strength of horizontally cored gneiss specimens are 29.688–45.760 GPa, 0.186–0.386, and 174.94–147.80 MPa, respectively; the elastic compression modulus, Poisson’s ratio and compressive strength of the vertical gneiss specimens are 26.541–32.602 GPa, 0.429–0.476 and 169.37–134.46 MPa. (3) The tensile modulus of the horizontal gneiss specimens is 4.93–5.98 GPa. The tensile modulus of the vertical gneiss specimens is 0.96–2.11 GPa. The tensile modulus of the horizontal gneiss specimens is five times that of the vertical gneiss specimens. The elastic compression modulus of gneiss is 5–20 times that of the tensile modulus. (4) The tensile strength and peak energy rate of horizontally cored gneiss specimens are 14.33–17.55 MPa and 2598.67–4049.53 J/m², respectively. The tensile strength of the vertical gneiss specimens is 6.12–9.65 MPa, and the peak energy rate is 715.74–1515.30 J/m². (5) There is a good linear relationship between the peak energy rate and tensile strength of gneiss. The research results can provide a scientific and reasonable reference for in situ fracturing of Bozhong 196 gas field.

The rheology of a partially hydrolyzed polyacrylamide (HPAM) solution plays an important role in its oil recovery during polymer flooding. However, multiple factors in brine, such as sulfide ions, cause a dramatic loss in the viscosity and oil recovery. To better understand the sulfide-induced viscosity loss and the consequent flow mechanisms in pore networks, the morphology of polymer solutions with and without sulfide ion was observed by scanning electron microscopy; and the variations of the pore scale flow fields were demonstrated by a microscopic visualization seepage experiment combined with Micro-PIV (Microscale Particle Image Velocimetry). The results showed that, with the presence of sulfide ion, the microstructure of the polymer changed from a uniform three-dimensional network structure to loose and uneven floccules, which resulted in viscosity loss (over 70% with 5-mg/L sulfide ion). Moreover, higher concentrations of sulfide ions (5 mg/L and 10 mg/L) resulted in earlier shear thinning characteristics than those with lower sulfide concentrations. Due to viscosity loss, the average flow velocity in the main stream of the microscopic seepage experiment increased more significantly than that without sulfide. However, the viscosity loss alone cannot independently explain the severe viscous fingering during the subsequent post-water flooding, which was about five times greater than that of the primary water flooding in terms of the velocity ratio between the mainstream and margin. A further pore-scale flow field analysis exhibited an eccentric and a bimodal velocity distribution in the throat along the radial and axial directions, respectively. The former distribution indicated that the adsorbed polymer on the pore wall was broken through by hydraulic shear due to the collapsed structure caused by sulfide ion. The latter suggested that another sulfide-induced impact was an earlier-occurring non-Newtonian characteristic with a low shear rate. Therefore, instead of viscosity loss, elastic loss is the dominant mechanism affecting the characteristics of the aggregate flow field under the action of sulfide. Microscopic flooding combined with Micro-PIV is a feasible and essential method to reveal pore scale flow mechanisms.

Horizontal well, dissolver, nitrogen, and steam (HDNS) combined flooding is mainly applied to shallow and thin heavy oil reservoirs to enhance oil recovery. Due to the lack of pore-scale mechanism studies, it is impossible to clarify the oil displacement mechanism of each slug in the process combination and the influence of their interaction on enhanced oil recovery (EOR). Therefore, in this study, HDNS combined flooding technology was simulated in a two-dimensional visualization microscopic model, and three viscosity reducer systems and multi-cycle combined flooding processes were considered. In combination with an emulsification and viscosity reduction experiment, two-dimensional microscopic multiphase seepage experiments were carried out to compare the dynamic seepage law and microscopic occurrence state of multiphase fluids in different systems. The results showed that the ability of three viscosity reducers to improve viscosity reduction efficiency in HDNS combined flooding was A > B > C, and their contributions to the recovery reached 65%, 41%, and 30%, respectively. In the system where a high viscosity reduction efficiency was shown by the viscosity reducer, the enhancements of both sweeping efficiency and displacement efficiency were primarily influenced by the viscosity reducer flooding. Steam flooding collaborated to improve displacement efficiency. The thermal insulation characteristics of N₂ flooding may not provide a gain effect. In the system where a low viscosity reduction efficiency was shown by the viscosity reducer, the steam flooding was more important, contributing to 57% of the sweeping efficiency. Nitrogen was helpful for expanding the sweep area of the subsequent steam and viscosity reducer, and the gain effect of the thermal insulation steam chamber significantly improved the displacement efficiency of the subsequent steam flooding by 25%. The interaction of each slug in HDNS combined flooding resulted in the additive effect of increasing production. In actual production, it is necessary to optimize the process and screen the viscosity reducer according to the actual conditions of the reservoir and the characteristics of different viscosity reducers.