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During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures. [ABSTRACT FROM AUTHOR]

In view of the short effective period of conventional foam for water shutoff during oil and gas reservoir development, a strong stability gel foam system is proposed in this work. By comparing the foam properties of different foaming systems, the optimized formulation of foam system is "0.3% SDS (sodium dodecyl sulfate) + 0.4% HPAM (partially hydrolyzed polyacrylamide) + 0.3% SD-107 (organic chromium)." At 50 °C and 10 000 mg/l salinities, the volume of foam is basically unchanged after a short time of defoaming and finally remains above 70%, and the drainage half-life can reach 16 days. The polymer and crosslinker form a stable three-dimensional network structure on the Plateau boundary after foaming, which has good viscosity and viscoelasticity. The foam system has excellent temperature and salt resistance. It is appropriate for medium and low temperature shallow reservoirs. The foam system has a good plugging efficiency. It can effectively plug the fracture and improve the sweep volume, which has a good application prospect. [ABSTRACT FROM AUTHOR]

The carbonate reservoir plays a pivotal role in conventional oil and gas reservoirs. However, due to limited knowledge of fluid flow characteristics in fractured-vuggy carbonate formations (vuggy means a small to medium-sized cavity inside rock), high efficiency reservoir development remains challenging. In this study, the similarity principle is utilized to design a two-dimensional visual model based on geological data and the injection-production characteristics of a fractured-vuggy reservoir in M Oilfield. To investigate the characteristics of oil–water flow, the oil–water interface, and residual oil distribution, flooding experiments are conducted at various injection-production positions, types, and injection rates. The results suggest that a low injection/high production strategy is optimal for achieving maximum oil recovery. As a consequence, this configuration is employed in the subsequent flooding experiments. The optimal oil recovery of 82.2% is attained via pore injection and vug production. The Jamin effect exerts an influence on the oil-water flow in structures connected by small channels at the bottom of large vugs, necessitating adjustment of the flow rate to achieve optimal injection conditions. The variation of the oil–water interface height in each vug due to structural flaws results in suboptimal overall oil recovery. The oil recovery is limited to approximately 30% at an injection rate below 8 ml/min but can be enhanced to over 70% with a higher injection rate exceeding 8 ml/min. The residual oil of the fractured-vuggy reservoir is typically found in the tops of structures and peripheral areas with poor connectivity. The findings of this study offer direction for optimal production in fractured-vuggy carbonate reservoirs and facilitate a more comprehensive comprehension of oil–water flows within the reservoir. [ABSTRACT FROM AUTHOR]

Water injection is often used to improve oil and gas recovery in the late stage of oil and gas reservoir development. Studies show that this process leads to complex changes in reservoir resistivity and affects the evaluation of remaining oil and gas saturation in the reservoir. In this study, a multi-point resistivity measurement experimental system suitable for full-diameter rock samples during fluid displacement was designed to simulate and explore the distribution and variation of resistivity in the reservoir flooding process. In this regard, two columnar electrodes were installed on the end face of the core sample to serve as fluid injection and outflow channels. Moreover, five groups of nail-shaped electrodes arranged at equal intervals were embedded on the rubber sleeve of the core holder. The electrical bridge metering combined with seven electrodes was used to measure the resistivity and variation of six parts of the core sample during fluid displacement. A confining pressure was applied to the core sample to simulate the underground high-pressure environment and force the nail-shaped electrodes to cling to the sample to improve the accuracy of resistivity measurement. The simulated water flooding experiment was carried out with a sandstone sample from Tarim Oilfield in western China, and the distribution and variation of the sample's resistivity were recorded. The experimental results conform to the laws of rock physics and confirm the reliability of the experimental system. The experimental system provides a guideline for determining the resistivity variation and evaluating the remaining oil and gas saturation of water-flooded reservoirs. [ABSTRACT FROM AUTHOR]

The complex fracture network in unconventional oil and gas reservoirs is the main channel for the fluid flow, and effective prediction of fracture network permeability is the basis for further accurate assessment of oil and gas productivity. On the basis of the traditional parallel-plate cube law, we introduce the tortuosity fractal dimension DTf to characterize the tortuosity of fractures. Then, combined with fractal theory, a permeability model is derived for a complex tortuous discrete fracture network (DFN). A pixel probability decomposition algorithm is used to generate ten random DFNs that conform to the fractal scale relationship, and the effectiveness of the proposed model is verified by numerical simulation. The fracture geometry parameters are further analyzed and their effect on permeability discussed. The results show that the permeability K of a fracture network increases with an increase in porosity ϕ (0.117–0.292), fractal dimension Df (1.635–1.824), maximum fracture length lmax (3.337–7.472 m), and proportionality coefficient β (0.00108–0.0164), but decreases with the increasing tortuosity fractal dimension DTf (1.0018–1.0196) and fracture dip angle θ (10°–80°). Among these parameters, Df, DTf, and β have the greatest influence on the permeability of the fracture network, followed by θ, lmax, and ϕ. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition is significantly influenced by rock wettability, and it has been extensively studied in core-based experiments and numerical simulations owing to its important role in the development of oil/gas reservoir. Due to the fine pore structure and complex wettability of tight sandstone, an in-depth exploration of the effects of wettability on the pore-scale flow physics during spontaneous imbibition is of great value to complement traditional experimental studies and enhance the understanding of microscopic flow mechanisms during the development of tight oil reservoirs. Based on a X-ray computed tomography scanning experiment and a lattice Boltzmann multiphase model, in this work, we systematically investigate the effects of different hydrophilic strengths on the evolution of the imbibition fronts within the micropores and the degree of nonwetting fluid recovery during spontaneous imbibition of tight sandstone. The results show that the wettability significantly affects the morphological characteristics of the imbibition fronts. Under strong hydrophilic conditions, the wetting fluid preferentially invades the pore corner in the form of angular flow. As the contact angle increases, the hysteresis effect at the main terminal interface decreases, and the two-phase interface becomes regular and compact. Wettability also significantly affects the imbibition rate and the nonwetting fluid recovery degree. The smaller the contact angle, the faster the imbibition rate and the higher the recovery degree of nonwetting fluids during the cocurrent spontaneous imbibition. [ABSTRACT FROM AUTHOR]