Browsing by Subject "Capillary Pressure"
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Item Fast Marching Method with Multiphase Flow and Compositional Effects(2014-08-06) Fujita, YusukeIn current petroleum industry, there is a lack of effective reservoir simulators for modeling shale and tight sand reservoirs. An unconventional resource modeling requires an accurate flow characterization of complex transport mechanisms caused by the interactions among fractures, inorganic matrices, and organic rocks. Pore size in shale and tight sand reservoirs typically ranges in nanometers, which results in ultralow permeability (nanodarcies) and a high capillary pressure in the confined space. In such extremely low permeability reservoirs, adsorption/desorption and diffusive flow processes play important roles for a fluid flow behavior in addition to heterogeneity-driven convective flow. In this study, the concept of ?Diffusive Time of Flight? (DTOF) is generalized for multiphase and multicomponent flow problems on the basis of the asymptotic theory. The proposed approach consists of two decoupled steps ? (1) calculation of well drainage volumes along a propagating ?peak? pressure front, and (2) numerical simulation based on the transformed 1-D coordinates. Geological heterogeneities distributed in 3-D space are integrated by tracking the propagation of ?peak? pressure front using a ?Fast Marching Method? (FMM), and subsequently, the drainage volumes are evaluated along the outwardly propagation contours. A DTOF-based numerical simulation is performed by treating a series of the DTOF as a spatial coordinate. This approach is analogous to streamline simulation, whereby a multidimensional simulation is transformed into 1-D coordinates resulting in substantial savings in computational time, thus allowing for high resolution simulation. However, instead of using a convective time of flight (CTOF), a diffusive time of flight is introduced in the modeling of a pressure front propagation. The overall workflow, which consist of the FMM and numerical simulation, is described in detail for single-phase, two-phase, blackoil, and compositional cases. The model validation is firstly performed on single-porosity systems with and without geological heterogeneity, then extended to multi-continuum domains including dual-porosity fractured reservoir and triple-continuum system. The large-scale unconventional models are finally demonstrated in consideration of the permeability correction for shale gas system and capillarity incorporation for confined phase behavior in multiphase shale oil system.Item Permeability prediction and drainage capillary pressure simulation in sandstone reservoirs(Texas A&M University, 2005-02-17) Wu, TaoKnowledge of reservoir porosity, permeability, and capillary pressure is essential to exploration and production of hydrocarbons. Although porosity can be interpreted fairly accurately from well logs, permeability and capillary pressure must be measured from core. Estimating permeability and capillary pressure from well logs would be valuable where cores are unavailable. This study is to correlate permeability with porosity to predict permeability and capillary pressures. Relationships between permeability to porosity can be complicated by diagenetic processes like compaction, cementation, dissolution, and occurrence of clay minerals. These diagenetic alterations can reduce total porosity, and more importantly, reduce effective porosity available for fluid flow. To better predict permeability, effective porosity needs to be estimated. A general equation is proposed to estimate effective porosity. Permeability is predicted from effective porosity by empirical and theoretical equations. A new capillary pressure model is proposed. It is based on previous study, and largely empirical. It is tested with over 200 samples covering a wide range of lithology (clean sandstone, shaly sandstone, and carbonates dominated by intergranular pores). Parameters in this model include: interfacial tension, contact angle, shape factor, porosity, permeability, irreducible water saturation, and displacement pressure. These parameters can be measured from routine core analysis, estimated from well log, and assumed. An empirical equation is proposed to calculate displacement pressure from porosity and permeability. The new capillary-pressure model is applied to evaluate sealing capacity of seals, calculate transition zone thickness and saturation above free water level in reservoirs. Good results are achieved through integration of well log data, production data, core, and geological concepts.