Search Results (8)

Studies have demonstrated that heavy oil flow exhibits threshold pressure gradient (TPG) which is closely related to the permeability and viscosity of the crude oil. Also, long-term water flooding continuously alters unconsolidated sandstone reservoir permeability through water flushing. These combined effects significantly influence water flooding performance. Therefore, in this paper, a comprehensive oil–water two phase mathematical model is developed for waterflooded heavy oil unconsolidated sandstone reservoirs based on the traditional black oil model, incorporating both time-varying permeability and threshold pressure gradient. The water-flooding-dependent threshold pressure gradient is firstly proposed, accounting for time-varying permeability. Subsequently, a simulator is developed with finite volume and Newton iteration method. Good agreement is obtained with the commercial simulator based on traditional black oil model. Afterward, the influence of permeability time variation and threshold pressure gradient is analyzed in detail. Results demonstrate that the threshold pressure gradient and time-varying permeability both decrease the oil recovery. The threshold pressure gradient (TPG) reduces the oil flow region and displacement efficiency since production. The increases in permeability after long term water flooding exacerbate reservoir heterogeneity and reduce sweep efficiency. The lowest oil recovery is observed when non-Darcy flow and permeability time variation are considered simultaneously. Furthermore, the time-varying threshold pressure gradient is observed with permeability time variation. Finally, a field data history matching was successfully performed, demonstrating the practical applicability of the proposed model. This new model better aligns with reservoir development characteristics. It can provide a theoretical guide for the development of heavy oil reservoirs. Full article

Understanding the spatiotemporal dynamics of short-duration heavy rainfall (SDHR) is critical for urban flood management. This study applies the K-shape clustering algorithm to classify 105 SDHR events in Beijing (2009–2021) using hourly rainfall data. Compared to K-means and DTW, K-shape prioritizes temporal shape alignment, crucial for capturing phase-shifted rainfall patterns. Three clusters emerged: (1) localized moderate-intensity events (13.3% of events) peaking at noon (11:00–14:00 LST) in western/southeastern regions, with weak burstiness (44.3% stations peak within 0–1 h) and moderate spatial variability (Cv = 1.08); (2) highly variable, intense urban rainfall (47.6% of events) characterized by rapid burstiness (72.5% stations peak within 0–1 h) and extreme spatial heterogeneity (Cv = 1.21), concentrated in central urban areas with peak intensities >130 mm/h; (3) prolonged heavy rainfall (39.1% of events) lasting >6 h, featuring significant accumulation (mean > 50 mm/day) in northeastern plains. The framework identifies high-risk zones (e.g., Cluster 2’s urban flash floods) and informs adaptive drainage design (e.g., prolonged resilience for Cluster 3). This study highlights the necessity of combining statistical metrics with domain expertise for robust SDHR classification and provides insights for urban flood management, emphasizing targeted strategies for different rainfall patterns. Full article

In the process of reservoir water flooding development, the characteristics of underground seepage field have changed, resulting in increasingly complex oil–water distribution. The original understanding of reservoir physical property parameters based on the initial stage of development is insufficient to guide reservoir development efforts in the extra-high water cut stage. To deeply investigate the spatio-temporal evolution of heterogeneity in the internal seepage field of layered reservoirs during water flooding development, water–oil displacement experimental simulations were conducted based on layered, normally graded models. By combining CT scanning technology and two-phase seepage theory, the variation patterns of heterogeneity in the seepage field of medium-to-high permeability, normally graded reservoirs were analyzed. The results indicate that the effectiveness of water flooding development is doubly constrained by differences in oil–water seepage capacities and the heterogeneity of the seepage field. During the development process, both the reservoir’s flow capacity and the heterogeneity of the seepage field are in a state of continuous change. Influenced by the extra resistance brought about by multiphase flow, the reservoir’s flow capacity drops to 41.6% of the absolute permeability in the extra-high water cut stage. Based on differences in the variation amplitudes of oil–water-phase permeabilities, changes in the heterogeneity of the internal seepage field of the reservoir can be broadly divided into periods of drastic change and relative stability. During the drastic change stage, the fluctuation amplitude of the water-phase permeability variation coefficient is 114.5 times that of the relative stable phase, while the fluctuation amplitude of the oil-phase permeability variation coefficient is 5.2 times that of the stable stage. This study reveals the dynamic changes in reservoir seepage characteristics during the water injection process, providing guidance for water injection development in layered reservoirs. Full article

The reservoir properties of super-heavy oil reservoirs in fluvial sedimentation are relatively poor, with high heterogeneity directly affecting the steam injection rate and expansion velocity of the steam chamber in the SAGD process. In order to significantly improve SAGD production performance, a combination of laboratory testing and physical simulation experiments was used to analyze the changes in reservoir-rock structure, rock geomechanical characteristics, and porosity and permeability during high-pressure injection, through rock geomechanics testing, core-flood experiment, and SEM scanning analysis. Large-scale two-dimensional physical simulation experiments were designed to analyze the effect of different injection agents in assisting the expansion of steam chambers. The experimental results showed that, with the increase in injection pore pressure, the reservoir permeability increased from 2.74 D to 4.56 D, and the contact between rock particles became looser after expansion, indicating a significant improvement in reservoir properties through high-pressure-injection-induced dilation. The results of the two-dimensional physical simulation experiments demonstrated that the solvent-assisted steam-chamber dilation speed was further increased compared with the conventional huff-n-puff dilation. Cyclic gas-injection volume can be increased from 0.16 PV in pure-steam injection cases to 0.32 PV. The hybrid-agent system of solvent-plus-gas can produce the dual positive effect of solvent dissolution and gas diffusion, more effectively improve the steam-chamber expansion speed, enhance the phased oil-recovery degree by 23.41%, and increase the oil/steam ratio from 0.27 to 0.33, indicating encouraging potentials in improving heavy oil and bitumen production performance by the dilation strategy. Full article

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low–medium-permeability reservoir porous media is crucial for HPCF treatment in a low–medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low–medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55–72 and β is 3.4–6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding. Full article

Heterogeneous phase composite (HPC) flooding technology that is based on branched-preformed particle gel (B-PPG) is an important technology for enhancing oil recovery in high water-cut reservoirs. In this paper, we conducted a series of visualization experiments under the condition of developed high-permeability channels after polymer flooding, with respect to well pattern densification and adjustment, and HPC flooding and its synergistic regulation. The experiments show that for polymer-flooded reservoirs, HPC flooding can significantly reduce the water cut and increase oil recovery, but that the injected HPC system mainly advances along the high-permeability channel with limited sweep expansion. Furthermore, well pattern densification and adjustment can divert the original mainstream direction, which has a positive effect on HPC flooding, and can effectively expand the sweeping range under the synergistic effect of residual polymers. Due to the synergistic effect of multiple chemical agents in the HPC system, after well pattern densification and adjustment, the production time for HPC flooding with the water cut lower than 95% was significantly prolonged. In addition, conversion schemes, in which the original production well is converted into the injection well, are better than non-conversion schemes in terms of expanding sweep efficiency and enhancing oil recovery. Therefore, for well groups with obvious high-water-consuming channels after polymer flooding, the implementation of HPC flooding can be combined with well pattern conversion and intensification in order to further improve oil displacement. Full article

This work uses micromodel, core floods and Field-Flow Fractionation (FFF) evaluations to estimate the behaviour and key elements for selecting polymers to address heterogenous reservoirs. One of the approaches was to construct two-layered micromodels differing six times in permeability and based on the physical characteristics of a Bentheimer sandstone. Further, the impacts of injectivity and displacement efficiency of the chosen polymers were then assessed using single- and two-phase core tests. Moreover, FFF was also used to assess the polymers’ conformity, gyration radii, and molecular weight distribution. For the polymer selection for field application, we weighted on the good laboratory performance in terms of sweep efficiency improvement, injectivity, and propagation. Based on the results, polymer B (highest MWD) performed the poorest. Full spectrum MWD measurement using Field-Flow Fractionation is a key in understanding polymer behavior. Heterogenous micromodel evaluations provided consistent data to subsequent core flood evaluations and were in alignment with FFF indications. Single-phase core floods performed higher injection velocities (5 m/d) in combination of FFF showed that narrower MWD distribution polymers (polymers A and C) have less retention and better injectivity. Two-phase core floods performed at low, reservoir representative velocities (1 ft/d) showed that Polymer B could not be injected, with pressure response staying at high values even when chase brine is injected. Adsorption values for all tested polymers at these conditions were high, however highest were observed in the case of polymer B. Overall, for the polymer selection for field application, we weighted on the good laboratory performance in terms of sweep efficiency improvement, injectivity, polymer retention, and propagation; all accounted in this work. Full article

The heterogeneous phase combination flooding (HPCF) system which is composed of a branched-preformed particle gel (B-PPG), polymer, and surfactant has been proposed to enhance oil recovery after polymer flooding in heterogeneous reservoirs by mobility control and reducing oil–water interfacial tension. However, the high cost of chemicals can make this process economically challenging in an era of low oil prices. Thus, in an era of low oil prices, it is becoming even more essential to optimize the heterogeneous phase combination flooding design. In order to optimize the HPCF process, the injection strategy has been designed such that the incremental oil recovery can be maximized using the corresponding combination of the B-PPG, polymer, and surfactant, thereby ensuring a more economically-viable recovery process. Different HPCF injection strategies including simultaneous injection and alternation injection were investigated by conducting parallel sand pack flooding experiments and large-scale plate sand pack flooding experiments. Results show that based on the flow rate ratio, the pressure rising area and the incremental oil recovery, no matter whether the injection strategy is simultaneous injection or alternation injection of HPCF, the HPCF can significantly block high permeability zone, increase the sweep efficiency and oil displacement efficiency, and effectively improve oil recovery. Compared with the simultaneous injection mode, the alternation injection of HPCF can show better sweep efficiency and oil displacement efficiency. Moreover, when the slug of HPCF and polymer/surfactant with the equivalent economical cost is injected by alternation injection mode, as the alternating cycle increases, the incremental oil recovery increases. The remaining oil distribution at different flooding stages investigated by conducting large-scale plate sand pack flooding experiments shows that alternation injection of HPCF can recover more remaining oil in the low permeability zone than simultaneous injection. Hence, these findings could provide the guidance for developing the injection strategy of HPCF to further enhance oil recovery after polymer flooding in heterogeneous reservoirs in the era of low oil prices. Full article