Due to the spatial network structure, heavy oil has a high threshold pressure gradient when it flows through porous media, and the threshold pressure gradient plays a crucial role in the distribution of remaining oil. In previous study, the common methods to measure the threshold pressure gradient include the microflow-established differential pressure (MFEDP) method, capillary equilibrium method, and the percolation curve fitting method. In this study, a sample from the SZ36-1 oilfield was analyzed for the basic physical properties based on the comparison of the previous measurement to study the influence of mobility on the threshold pressure gradient and then an independently developed numerical simulator was established to study the effect of the threshold pressure gradient on the remaining oil distribution considering the permeability range, crude oil viscosity, well network deployment, well spacing, and fluid recovery rate. The results show that the SZ36-1 oilfield fluid belongs to Bingham fluids with yield stress and the mobility having an exponent relation to the threshold pressure gradient based on the measurement of the MFEDP method. Considering the threshold pressure gradient of heavy oil, the uneven distribution of remaining oil is intensified and the remaining oil is enriched. This study provides a reference for efficient development of heavy oil reservoirs.

Addressing the challenge of significant physical property variations in heterogeneous reservoirs, where conventional water flooding easily induces channeling, the current research focus lies in utilizing CO₂–water alternating gas (CO₂–WAG) or a CO₂–water/polymer composite alternating flooding to control fluid mobility and reduce gas channeling, thereby enhancing oil displacement efficiency. While existing studies primarily concentrate on single-reservoir types (e.g., purely high permeability or purely low permeability), this research employs core samples from the TX block (predominantly medium-high permeability) and CS block (predominantly medium-low permeability) of a specific oilfield. By adjustment of the size of periodic slugs, parallel long-core flooding experiments were sequentially conducted for CO₂–WAG and CO₂–water/polymer alternating flooding. Nuclear magnetic resonance (NMR) technology was integrated to quantitatively characterize the oil displacement effectiveness of the composite CO₂–water/polymer flooding under different heterogeneous physical properties and microscopic pore characteristics. The experimental results indicate that during CO₂–WAG flooding, the core recovery factor from the TX block (medium-high perm) was higher than that from the CS block (medium-low perm). During CO₂–water/polymer composite alternating flooding, the core recovery factor from the CS block (medium-low perm) exceeded that from the TX block (medium-high perm). CO₂–WAG effectively mitigates gas channeling in medium-high permeability heterogeneous reservoirs, while CO₂–water/polymer alternating flooding effectively reduces gas channeling in medium-low permeability heterogeneous reservoirs and enlarges the microscopic swept volume. The conclusions of this study provide a theoretical basis and a practical reference for the differentiated development of similar reservoirs.

The depletion of conventional oil resources has rendered heavy oil development a critical challenge in the energy sector. As a core rheological parameter of heavy oil, yield stress directly influences transportation efficiency and the optimization of oil displacement strategies. This study employs a multiscale analytical approach, integrating ultraviolet absorption spectroscopy and rheological testing, to systematically investigate the mechanisms by which saturate, aromatic, resin, and asphaltene (SARA) components in heavy oil and their interactions affect yield stress. The findings reveal distinct impacts of individual components on yield stress: Saturates monotonically reduce yield stress via solvation effects; Aromatics exhibit a peak–valley trend, increasing yield stress to a maximum within a specific content range before decreasing; Resins progressively elevate yield stress with increasing content by forming micellar systems that enhance structural strength; Asphaltenes display a U-shaped influence, initially disrupting resin-asphaltene complexes to reduce yield stress, followed by significant yield stress increases beyond a critical concentration due to the formation of three-dimensional network structures. Molecular interaction analysis demonstrates that saturates exhibit dual effects, aromatics reduce structural integrity by dispersing asphaltene aggregates, resins bind with asphaltenes through multifaceted interactions, and asphaltenesowing to their strongest polarityact as the structural core of networks. Elevated temperatures substantially weaken intercomponent interactions, leading to colloid network destabilization and widespread yield stress reduction. This research establishes a comprehensive theoretical framework bridging molecular mechanisms to macroscopic performance, providing crucial scientific insights for both theoretical advancements in heavy oil rheology and practical engineering applications.

The Threshold Pressure Gradient (TPG) phenomenon exerts a profound influence on fluid flow dynamics in heavy oil reservoirs. However, the discrepancies between the True Threshold Pressure Gradient (TTPG) and Pseudo-Threshold Pressure Gradient (PTPG) significantly impede accurate residual oil evaluation and rational field development planning. This study proposes a dual-exponential conversion model that effectively bridges the discrepancy between TTPG and PTPG, achieving an average deviation of 12.77–17.89% between calculated and measured TTPG values. Nonlinear seepage simulations demonstrate that TTPG induces distinct flow barrier effects, driving residual oil accumulation within low-permeability interlayers and the formation of well-defined “dead oil zones.” In contrast, the linear approximation inherent in PTPG overestimates flow initiation resistance, resulting in a 47% reduction in recovery efficiency and widespread residual oil enrichment. By developing a TTPG–PTPG conversion model and incorporating genuine nonlinear seepage characteristics into simulations, this study effectively mitigates the systematic errors arising from the linear PTPG assumption, thereby providing a scientific basis for accurately predicting residual oil distribution and enhancing oil recovery efficiency.

Carbon capture, utilization, and storage (CCUS) is a core technology for achieving carbon neutrality. The safety of geological carbon storage is crucial for its large-scale application, and the response characteristics of surface water environments to CO₂ leakage directly determine the effectiveness of safety early warning systems. This study, conducted in the CCUS demonstration area of Shengli Oilfield, employs a combination of laboratory simulation experiments and in situ field monitoring campaigns to systematically clarify the dynamic response patterns of multiple surface water environmental indicators under different leakage scenarios. Sensitive indicators are identified, and hierarchical early warning thresholds are established. Results indicate that CO₂ concentration and pH exhibit the most stable and sensitive responses to leakage, making them ideal core discriminant indicators. Electrical conductivity and total dissolved solids exhibit significant increases during leakage events, making them suitable as auxiliary verification indicators. By comparison, the response characteristics of phosphate ions, chemical oxygen demand, and certain metal ions demonstrate strong environmental dependence. Additionally, a surface water monitoring system covering the "core-auxiliary-reference" three-level indicator framework was established. A critical threshold of CO₂ concentration >1000 ppm and pH < 6 was proposed to diagnose leakage. This study provides a systematic theoretical basis and technical support for the safety assessment and risk early warning of surface water environments in CCUS project areas.

Conventional waterflooding in low- to medium-permeability (LMP) sandstone reservoirs is prone to preferential flow, early water channeling, and insufficient sweep efficiency. To clarify the effects of pulsed waterflooding on oil mobilization and residual oil distribution in different pore-size domains, continuous and pulsed waterflooding experiments were conducted in single-core and dual-core parallel systems, and low-field nuclear magnetic resonance (LF-NMR) T2 measurements were used to characterize fluid changes in different pore size ranges before and after flooding. The results show that the recovery factor of single-core continuous waterflooding exhibited a nonmonotonic relationship with the injection rate, reaching a maximum of 32.53% at 0.20 mL/min. An excessively low injection rate provided insufficient displacement pressure, whereas an excessively high injection rate strengthened preferential flow, both of which were unfavorable for oil mobilization in small pores and poorly connected pore throats. Single-core pulsed waterflooding showed clear schedule dependence, with the highest final recovery of 39.64% achieved under the 15/15 min schedule. In dual-core parallel pulsed waterflooding, the recovery of the high-permeability core was consistently higher than that of the low-permeability core, reaching 35.83% and 19.48%, respectively, under a 30/30 min schedule. The NMR T2 results indicate that continuous waterflooding mainly mobilized oil in large-pore domains, whereas pulsed waterflooding promoted displacement toward small pores and poorly connected pore throats through viscous displacement during injection, pressure re-equilibration during shut-in, and capillary-driven fluid exchange. Overall, pulsed waterflooding can improve pore-size-resolved oil mobilization in LMP cores, but its effectiveness is jointly controlled by the injection/shut-in schedule, pore throat connectivity, flow resistance, and flow partitioning in parallel systems.