The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO₂ saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO₂ seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO₂ injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO₂ injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO₂–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies.

Relative permeability is a fundamental parameter affecting reservoir development performance analysis. During the development of oil and gas fields, the displacement pressure gradient changes with time and space. This paper studies the effect of displacement pressure gradient on relative permeability. The oil–water relative permeability curves of a Bohai Oilfield under different displacement pressure gradients are obtained through experimental analysis. Based on the experimental data, a correction model of the permeability curve is established by regression of the Willhite model parameters. The correction model is introduced into the black oil numerical simulation, and the production performance and remaining oil are compared and analyzed. The results show that the displacement pressure gradient can have an obvious impact on the relative permeability curve. As the displacement pressure gradient increases, the two-phase span of the relative permeability curve increases, the oil displacement efficiency increases, and the water relative permeability increases. The relative permeability curves under different displacement pressure gradients can be accurately characterized by the Willhite model. The consideration of the displacement pressure gradient has an obvious impact on numerical simulation results. The conventional method of using a fixed relative permeability curve cannot truly reflect the production performance and the remaining oil distribution. This paper proposes a set of realization methods including obtaining laws from experiments, utilizing the empirical model to correct, and simulating to characterize reservoir changes.

Increasing oil production is crucial for multilayer co-production. When there are significant differences in the permeability of each layer, an interlayer contradiction arises that can impact the recovery efficiency. After a number of tests and the establishment of a mathematical model, the effects of permeability contrast on oil production for water flooding were revealed. In the meantime, the developed mathematical model was solved using the Buckley–Lever seepage equation. Ultimately, the accuracy of the established model was confirmed by comparing the simulated outcomes of the mathematical model with the experimental results. The findings indicate that when permeability contrast increases, the production ratio of the high-permeability layer will improve. This is primarily due to the low-permeability layer’s production contribution rate decreasing. The accuracy of the established model is ensured by an error of less than 5% between the results of the experiment and the simulation. When the permeability contrast is less than three, the low-permeability layer can be effectively used for three-layer commingled production. However, when the permeability contrast exceeds six, the production coefficient of the low-permeability layer will be less than 5%, which has a significant impact on the layer’s development.

Complex narrow-channel reservoirs are strongly constrained by depositional architecture, resulting in highly nonuniform areal waterflood sweep, and pronounced water-cut variations among different channel types. These characteristics pose substantial challenges to stabilizing oil production and controlling water cut at high water-cut stages. To elucidate how narrow-channel planform architecture controls waterflood sweep, gel-assisted flow-field regulation by heterogeneous-phase composite flooding (HPCF), and remaining-oil mobilization, three representative configurations were reproduced in two-dimensional visual physical models. Sequential waterflood–HPCF–post-waterflood experiments were conducted, and time-lapse images and dynamic production data were integrated to characterize sweep evolution and remaining-oil mobilization across displacement stages. The results demonstrate that narrow-channel architecture exerts primary control on preferential flow-path development, gel migration and retention, spatial fluid redistribution, and displacement performance. During waterflooding, injected water preferentially migrated through high-permeability zones along channel centerlines, leaving channel margins, branch termini, and poorly connected regions insufficiently swept. After HPCF injection, the gel-containing composite system preferentially entered the established dominant flow paths. Gel retention and accumulation selectively increased flow resistance in these pathways, while mobility control induced subsequent fluids to divert toward bypassed regions, thereby enlarging the macroscopic swept volume and improving local displacement efficiency. A low injection rate promoted sustained gel-assisted flow diversion within bifurcated channels, whereas a high injection rate facilitated gel-slug propagation against the geometric constraints of highly sinuous channels and expanded its spatial coverage. Compared with waterflooding alone, HPCF increased the ultimate oil recovery of the three channel models by 19.23–26.47 percentage points. These findings clarify the coupled effects of narrow-channel architecture, gel transport and injection parameters on the profile-control and oil-recovery performance of HPCF, providing a mechanistic basis for water control and development optimization in high-water-cut narrow-channel reservoirs.

Archaean metamorphic basement reservoirs, characterized by the development of natural fractures, constitute the primary target for oil and gas exploration in the Bozhong Depression, Bohai Bay Basin, Eastern China. Based on analyses of geophysical image logs, cores, scanning electron microscopy (SEM), and laboratory measurements, tectonic fractures are identified as the dominant type of natural fracture. Their development is primarily controlled by lithology, weathering intensity, and faulting. Fractures preferentially develop in metamorphic rocks with low plastic mineral content and are positively correlated with weathering intensity. Fracture orientations are predominantly parallel or subparallel to fault strikes, while localized stress perturbations induced by faulting significantly increase fracture density. Open fractures, constituting more than 60% of the total reservoir porosity, serve as both primary storage spaces and dominant fluid flow conduits, fundamentally governing reservoir quality. Consequently, spatial heterogeneity in fracture distribution drives distinct vertical zonation within the reservoir. The lithological units are ranked by fracture development potential (in descending order): leptynite, migmatitic granite, gneiss, cataclasite, diorite-porphyrite, and diabase. Diabase represents the lower threshold for effective reservoir formation, whereas overlying lithologies may function as reservoirs under favorable conditions. The large-scale compressional orogeny during the Indosinian period marked the primary phase of tectonic fracture formation. Subsequent uplift and inversion during the Yanshanian period further modified and overlaid the Indosinian structures. These structures are characterized by strong strike-slip strain, resulting in a series of conjugate shear fractures. During the Himalayan period, preexisting fractures were primarily reactivated, significantly influencing fracture effectiveness. The development model of the fracture network system in the metamorphic basement reservoirs of the study area is determined by a coupling mechanism of dominant lithology and multiphase fracturing. The spatial network reservoir system, under the control of multistage structure and weathering, is key to the formation of large-scale effective reservoirs in the metamorphic basement.

Fractured reservoirs have developed fractures, strong heterogeneity, and complex seepage patterns. The analysis of core and imaging logging data in Bohai BZ Oilfield shows that there are a large number of fractures developed in the formation, with some wells having up to 6-8 fractures per meter. To study the impact of fractures on seepage, a multi fracture system seepage field simulation method was established, and the characteristic curves of flow lines under different fracture shapes were drawn. The fracture flow line morphology shows that there is a significant difference in the distribution of flow lines between the presence and absence of fractures, and the location of the fractures The size and shape of the reservoir have varying degrees of influence on the distribution of the streamline. The streamline around the well is distributed radially around it. When the fluid encounters an area with developed fractures, it first flows into the fractures and then flows from the fractures towards the wellbore. At the same time, based on the characteristics of fracture development in BZ oilfield and the theory of vertical fracture well testing, a dual medium multi fracture system oil well testing model was established. The model was numerically solved using Laplace transform, and a dual logarithmic curve chart for dual pore medium multi branch fracture well testing was obtained. The effects of fracture branching number, fracture length, conductivity coefficient ratio, and fracture conductivity on the shape of the testing curve were analyzed. The established well testing interpretation model can analyze oilfield stratigraphic information, reservoir fracture development, and boundary conditions. The research results have important guiding significance for evaluating the dynamic performance of oil wells in a dual pore medium multi fracture system and designing oilfield development plans.