Dynamic fractures are a geological attribute of water flooding development in tight fractured oil reservoirs. However, previous studies have mainly focused on the opening mechanism of dynamic fractures and the influence of dynamic fractures on development. Few attempts have been made to investigate the optimization of the dynamic fracture parameter. In this study, the inverted square nine-spot well pattern model is established by taking fractured reservoir’s heterogeneity and its threshold pressure gradients into account. This simulation model optimizes the various parameters in a tight fractured oil reservoir with dynamic fractures, that is, the intersection angle between the dynamic fractures and the well array, the number of dynamic fractures, the penetration ratio, and the conductivity of the oil well’s hydraulic fractures. The results of this optimization are used to investigate the oil displacement mechanism of dynamic fractures and to discuss a mechanism to enhance oil recovery using an inverted square nine-spot well pattern. The simulation results indicate that a 45° intersection angle can effectively restrain the increase in the water cut. A single dynamic fracture can effectively control the displacement direction of the injected water and improve the oil displacement efficiency. Moreover, the optimal penetration ratio and the conductivity of the hydraulic fracture are 0.6 and 40 D-cm, respectively.
Due to its long lifespan and high sand-removal efficiency, gravel packing is one of the most applied sand control methods during the recovery of reservoirs with sanding problems. The blockage and retention of injected sand in a gravel pack is a complex process affected by multiple mechanisms. The majority of existing studies based on the phenomenological deep bed filtration (DBF) theory focused on the gravel pack's overall permeability damage and failed to obtain the inner-pore particle distribution pattern. In this work, experiments and simulations were carried out to reveal the particle distribution in a gravel pack during flooding. In particular, through real-time monitoring of particle migration, the penetration depth and distribution pattern of invaded particles with different gravel-sand particle ratios, fluid viscosities and injection rates could be determined. By simplifying each unit bed element (UBE) into a pore-throat structure with four tunnels (two horizontals for discharge and two verticals for sedimentation), a new network simulation method, which combines deep bed filtration with a particle trajectory model, was implemented. Cross comparison of experimental and numerical results demonstrates the validity and accuracy of the model.
—The Carboniferous Donghe sandstone reservoir is the most important target in the Tabei Uplift of the Tarim Basin, which contains a range of hydrocarbon types, including bitumen, heavy oil, condensate oil, light oil, crude oil, and hydrocarbon gas, and has high contents of CO2 and N2. The origin of multiple phase hydrocarbons from Carboniferous reservoir rocks in the Donghetang area, Western Tabei Uplift, is documented in this paper based on integral analysis of the geochemistry, pyrolysis, and carbon isotopes of the bulk composition and light composition hydrocarbons. Oil–source correlations determined that the paleoreservoir hydrocarbons that formed from Permian to Triassic derived from the Lower Ordovician (O1) source rocks and that those of the present-day reservoir that formed in the Neogene derived from Middle–Upper Ordovician (O2-3) source rocks. During the uplift episode lasting from Permian to Triassic, the hydrocarbons in the entire paleoreservoir underwent water washing, biodegradation, and bacterial sulfate reduction (BSR), resulting in residual bitumen, heavy oil, H2S, and pyrites in the paleoreservoir. The high CO2 and N2 contents originated from volcanic degassing due to volcanic activity from Permian to Early Triassic. The present-day reservoirs underwent gas washing and evaporative fractionation due to natural gas charging that originated from oil cracking and kerogen degradation in the deeper reservoirs; this resulted in fractionation and formed condensate oil and light oil with a high wax content in the residual crude oil. Based on this research, it was concluded that the diverse hydrocarbon phases in the Donghetang area were primarily attributed to water washing, biodegradation, BSR, volcanic degassing, gas washing, and evaporative fractionation.
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