Huazhou Li

Volume translation (VT) methods are widely used to improve the prediction accuracy of cubic equations of state (CEOSs); however, the existing VT models fail to reproduce the true critical molar volumes and often lose accuracy under extended temperature and pressure conditions. To overcome these limitations, we develop a unified distance-function-based VT model for CEOSs, leading to the volume-translated-rescaled CEOSs (VTR-CEOSs). These models not only exactly replicate the true critical molar volume but also maintain strong performance for both light-to-heavy pure compounds and mixtures over broad thermodynamic conditions. We then comprehensively compare the prediction capability of the proposed model against those of six representative volume translation models. The results demonstrate that our models can generally achieve the highest overall accuracy in predicting various properties. Moreover, the proposed VTR-CEOSs are verified to be thermodynamically consistent within the tested temperature and pressure ranges.

Summary: Effective water control in deep fractured-vuggy reservoirs remains a significant challenge due to extreme heterogeneity, high-temperature/high-salinity environments, and severe dilution of injected gelation solution by formation water. Conventional gel often fails under such conditions because dilution inhibits gelation. To address this, a novel dilution-resistant gel (DRG) engineered for deep-source water control by incorporating sodium alginate (0.4–0.6 wt%) was developed. Upon contact with calcium ion (Ca2+)-rich formation water, sodium alginate rapidly forms dense, impermeable interfacial membrane that encapsulates gelation solution, effectively shielding it from dilution and enabling successful gelation even at 1:10 gelation solution-to-formation water volumetric ratio. Laboratory evaluations under reservoir-representative conditions (130°C, 220,000 mg/L) confirmed DRG’s performance. Interfacial rheology measurements revealed stable elastic modulus (G′ = 5.99 Pa) and viscous modulus (G″ = 3.52 Pa), indicating a mechanically resilient barrier capable of withstanding dynamic flow. DRG demonstrated exceptional resistance to both static and dynamic dilution while maintaining excellent viscoelasticity. Microstructural analysis showed a refined, highly interconnected 3D network structure with pore sizes of 10–20 μm significantly denser than conventional gel (15–30 μm)—which enhances water retention and mechanical integrity. Moreover, thermal stability was markedly improved, with temperature limit elevated by 3.9°C (initial state) and 9.3°C (after 60 days of aging) compared with conventional gel. Fracture plugging, parallel fracture, and complex model visualized oil displacement experiments, validating the DRG’s field applicability. In fracture core (1–10 mm), DRG achieved stable plugging pressure gradients of 7.5–11.5 MPa/m under dilution—comparable with undiluted conventional gels. Compared with the primary waterflooding, DRG enhanced oil recovery by 22.34% and increased pressure by 38.04 kPa in the parallel fracture configuration, outperforming the conventional gel (13.07% and 22.12 kPa). In complex fracture and fractured-vuggy configurations, the DRG enabled effective multicycle water diversion, increasing sweep efficiency from 36.83% to 81.99% in fracture networks and from 43.52% to 95.13% in fractured-vuggy configurations. This DRG presents itself as a potential option for deep-source water control in complex deep fractured-vuggy reservoirs, providing an effective strategy to manage water production and enhanced oil recovery (EOR).

CO2 flooding can improve heavy-oil mobility, but CO2 readily channels through preferential pathways, limiting the swept volume and leaving substantial residual oil trapped in low-permeability regions and small-to-medium pores. In this work, the reservoir applicability of a frustrated Lewis pair-based CO2-reactive thickening polymeric surfactant system (PMSA/PMSB) is systematically evaluated, and its mechanisms for CO2 channeling control and residual-oil mobilization are investigated at both the core and pore scales. The results show that the PMSA/PMSB system exhibits good injectability and maintains plugging efficiencies above 85% in cores with permeabilities ranging from 500 × 10-3 to 4500 × 10-3 μm2. The suitable injection volume, injection rate, and aging time are determined to be 0.6–0.8 PV, 0.1–0.3 mL·min-1, and 24 h, respectively. Before CO2 triggering, the PMSA/PMSB can migrate through preferential pathways and become adsorbed and retained on rock surfaces and within the pore space. Upon CO2 triggering, the system forms a covalently crosslinked thickened network that increases the flow resistance of high-permeability channels through rock-surface coverage, pore-space filling, and pore-throat bridging, thereby redirecting subsequent CO2 toward previously poorly swept regions. Low-field nuclear magnetic resonance results show that oil recovery from small pores increases from 9.09% to 35.87%, while the overall oil recovery increases from 29.73% to 49.31%, corresponding to an incremental recovery of 19.58% after profile control. Pore-scale visualization further demonstrates that the PMSA/PMSB promotes the deformation, detachment, fragmentation, and migration of network-like, cluster-like, columnar, and film-like residual oil. This work reveals the synergistic mechanism among CO2-reactive thickening and plugging, fluid diversion, and emulsification-assisted residual-oil mobilization, providing a theoretical basis for CO2 channeling control and efficient residual-oil recovery in heavy oil reservoirs.

Channeling during viscosity reducer flooding in heterogeneous heavy oil reservoirs limits sweep efficiency, while conventional non‐selective agents often plug oil‐rich zones. To address this, a novel modified petroresin particle (MPRP) with oil–water selectivity was synthesized via graft copolymerization of 2‐acrylamido‐2‐methylpropanesulfonic acid (AMPS) onto dicyclopentadiene‐based resin (DCPD). Fourier‐transform infrared spectroscopy and X‐ray photoelectron spectroscopy confirmed the successful incorporation of hydrophilic groups while retaining the oil‐soluble backbone. MPRP exhibits excellent oil solubility (>84%) and aqueous dispersibility. Under reservoir conditions, temperature and mineralization trigger a 3.6–6.6‐fold particle size increase via cohesive expansion, inducing selective plugging in high‐permeability water channels to control channeling, while spontaneous dissolution in oil prevents formation damage. Systematic core flooding established the optimal adaptation threshold: 0–50 000 mg/L, 60°C–90°C, 0.1–3.0 D, in situ oil viscosity 1875 mPa·s, and permeability contrast 4.22–11.96. Field‐recommended injection parameters increased cumulative recovery from 28.32% to 57.54% in 1.0 D. NMR and micro‐visualization revealed that MPRP selectively plugs high‐permeability channels, diverting subsequent fluid into low‐permeability regions without injectivity impairment. The field test of MPRP achieved effective water production suppression and oil production enhancement, leading to an incremental oil production of 65.22 tons. This work establishes MPRP as a promising agent for conformance control in heavy oil production.

Spontaneous imbibition is a primary recovery mechanism in unconventional reservoirs. Although core-scale experiments capture the combined effects of parameters such as interfacial tension (IFT) and permeability, the individual roles of boundary conditions and gravity remain poorly understood at the pore scale. This study employed microfluidics to directly visualize and quantify these effects during chemically assisted spontaneous imbibition. Micromodels consisting of a tight matrix adjacent to a fracture were saturated with dyed kerosene. Two boundary conditions were examined: cocurrent imbibition, with two ends open, and countercurrent imbibition, with only one side open. Experiments were conducted in vertical and horizontal orientations using water and nonionic (Tween 80) and anionic (Enordet O342) surfactants. Time-lapse imaging was used to track imbibition dynamics. Quantitative metrics, including the imbibition front velocity, perimeter-area ratio, displacement efficiency, and recovery factor, were extracted to characterize the mechanics of the process. For water-only experiments, cocurrent imbibition produced smoother displacement fronts with reduced fingering and a higher displacement efficiency than countercurrent imbibition. Similar trends were observed in most of the chemical-assisted tests. Both surfactants enhanced the final recovery and displacement efficiency by stabilizing the imbibition front and reducing residual oil saturation. Horizontal experiments exhibited higher early time front velocities but more pronounced fingering and lower displacement efficiency than vertical experiments. In the absence of gravity, long unstable fingers formed rapidly and impeded the further recovery. In vertical water imbibition, a high capillary force dominated the process, which caused rapid but unstable fingering. Conversely, the application of chemical additives reduced the IFT and transitioned the system to a gravity-dominated regime, which effectively stabilized the front in the vertical orientation. The pore-scale morphologies and recovery trends were found to be governed by the interplay of the inverse Bond number, viscous coupling, and relative permeability.

Summary: In this study, we investigate the long-term integrity of well cements exposed to supercritical carbon dioxide (SC-CO2) and SC-CO2-saturated brine (sodium chloride, NaCl) solution for carbon capture and storage (CCS) applications. By analyzing the correlation among cement composition, carbonation patterns, and mechanical properties, the aim of our research is to demonstrate how exposure environments affect cement chemically and physically. Our findings provide information toward the design of durable cement formulations to enhance long-term zonal isolation in CCS application. Two cement systems—Class G (G), Class G with fly ash (GF)—are exposed to SC-CO2 and CO2-saturated brine at 70°C and 28.0 MPa (4,060 psi) for up to 6 months. Post-exposure characterization includes phenolphthalein tests, X-ray diffraction (XRD), thermogravimetric analysis (TGA), X-ray microscopy (XRM), permeability measurements, Vickers hardness testing, and uniaxial compressive strength (UCS) measurements. These methods link mineralogical changes, microstructural alteration, flowability assessment, and mechanical performance, providing insights into carbonation mechanisms and long-term cement integrity assessment under simulated downhole CCS conditions. High-portlandite cement (G) under SC-CO2 exposure demonstrates a competing mechanism between carbonation and CO2 diffusion. The rapid carbonation near the exposure surface forms calcium carbonate (CaCO3), which blocks pores and restricts further CO2 diffusion. Meanwhile, continuing CO2 diffusion through remaining pathways drives more carbonation. This competing process results in a distinct multilayer structure. While carbonation increases density and hardness, it raises integrity concerns due to the formation of brittle layers. Low-portlandite systems (GF) show uniform carbonation throughout, maintaining structural integrity. The transport mechanism in CO2-brine exposure is different. CO2 dissolves in brine to form carbonic acid, which then moves into the pores. Carbonation rates are slower than SC-CO2 exposure because CO2 concentration is lower in brine. This slower carbonation results in lower levels of CaCO3 formation and deep penetration of CO2-brine solutions into the cement matrix. Consequently, both G and GF cement in CO2-brine shows uniform carbonation with lower hardness increment when compared with SC-CO2 exposure samples. Permeability remains low in both cement systems despite structure and chemical alteration, validating cement’s sealing capacity within the test duration. In conclusion, cement composition affects carbonation mechanisms—high portlandite content drives stratified carbonation, while a well-engineered blend system with fly ash enables uniform carbonation. With this study, we provide a systematic comparison of cement carbonation mechanisms under both SC-CO2 and CO2-brine exposure over extended durations (up to 6 months). By correlating the results of chemical, physical, direct, and indirect techniques, our research reveals environment-specific carbonation mechanisms. These findings contribute to the understanding of the long-term performance of well cement systems in CCS applications, offering the pathway for optimizing cement designs and derisking well construction for CO2 storage.