Phase behavior and fluid properties are governed by molecule-molecule and molecule-pore wall interactions. The effect of molecule-pore wall interactions is negligible in conventional reservoirs because pore sizes are much larger than molecular mean free paths. However, this effect is very important in shale formations because the pore sizes in shale formations are in the order of nano-scale. Reservoir fluids properties and phase behavior under nanoscale confinement exhibit significant deviations from their bulk properties.This work used two methods to investigate the effect of pore proximity on the phase behavior and fluid properties: 1-Developing a new flash calculations algorithm: the influence of difference between oil and gas pressures (i.e. capillary pressure) is neglected in the flash calculations of vapor-liquid equilibrium for conventional reservoirs. However the capillary pressure is very high and cannot be ignored in phase behavior calculations of shale formations. A new mathematical expressions for chemical potentials of pure components and their mixture as a function of capillary pressure is proposed, and 2-Modifying the critical properties of pure components under the effect of confinement: new correlations based on molecular simulation studies are developed for taking into account the effect of pore size (i.e. molecule-pore wall interactions) on critical properties of each component. The modified critical properties are used in phase behavior calculations.Both methods were tested against experimental data of Sigmund et al. (1973) for C 1 -nC 5 mixtures. The relative errors between the prediction of bubble point pressures and gas compositions from the models and the reported experimental data were less than 5 %. Then phase behavior and fluid properties of a mixture of Methane, n-Butane and n-Octane with different compositions were studied under confinement for pore size range from infinity to 2 nm by using both methods. In general, the two-phase envelope shrinked slightly in method 1 and significantly in method 2 with decreasing the pore size. The effect of pore size on two-phase envelope becomes significant when pore radius is smaller than 10 nm. For method 1, critical point does not change and the closer of the temperature to the critical point, the smaller the change in saturation pressures. For method 2, the critical point decreases with the pore radius. Interfacial tension for bulk fluid and confined fluid remain about the same for pore sizes more than 50nm. For pore sizes less than 50nm, interfacial tension from method 1 did not change significantly, but it decreased dramatically especially for pore sizes less than 10nm when method 2 was used. K-values from both methods were almost the same for pore sizes more than 10nm. From method 1, k-value decreases with decreasing the pore radius for all components. But from method 2, it decreases for light component and increases for intermediate and heavy components.The results of this study can have a significant impact on our understanding of the gas ...

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Phase behavior and fluid properties in porous media are governed by not only fluid molecule-fluid molecule interactions but also fluid molecule-pore wall interactions. The current available equations of state consider only fluid molecule-fluid molecule interactions and neglect the interactions between the reservoir fluid molecules and the solid wall of the porous media. For conventional reservoirs, this assumption may be valid because the formation pore sizes are much larger than molecular mean free paths. However, in shale formations that are characterized by nanopores, the fluid molecule-pore wall interactions play such an important role that can change phase behavior and crticial properties of the reservoir fluids. Consequently, the critical temperatures and pressures of multi-component hydrocarbon mixtures under nanopores confinement are influenced strongly by fluid molecule-pore wall interactions. This work investigates the effect of pore proximity in tight and shale formations on phase behavior and fluid properties of the reservoir fluids by modifying van der Waals equation of state. Effects of both fluid molecule-fluid molecule and fluid molecule-pore wall interactions are included in the newly proposed equation of state. Based on molecular simulation studies, correlations are developed to consider the effect of fluid molecule-pore wall interactions for each component required for phase equilibria calculations under nanopore confinement using the proposed equation of state. Phase behavior calculations of a mixture of methane, n-butane and n-octane were studied under confinement effects for pore sizes ranging from 10 to 2 nm. In general, with the decrease of pore size, the two-phase region of the fluid mixture tends to shrink, which makes the fluid mixture behave more like a dry gas. The results indicate that bubble point and dew point pressures of the confined fluids are up to 150 psi and 300 psi higher than their correspondent bulk values. Also n-butane and n-octane tend to evaporate more when pore size dereases. The confinement effects can cause the fluid mixture to behave similar to dry gas, which results in reduction in condensate banking and less near-wellbore permeability impairment in comparison to conventional reservoirs. This has several implications for reservoir and well performances. One is that we can observe increased gas rates and enhanced recoveries over the life of the field by modeling these effects in a numerical reservoir simulation package.

Transport properties and mechanisms as well as phase behavior under nanoscale confinement exhibit significant deviations from their bulk behavior. This is due to the significant effect of molecule-wall interactions as well as molecule-molecule interactions in shale formations which are mainly characterized by nanopores. Consequently, production from shale gas reservoirs is strongly influenced by pore sizes and their effects on phase behavior and transport properties. In this study, we focus on analyzing and determining the effect of phase behavior and transport properties change due to pore proximity on production from a shale gas condensate reservoir. Additionally, the effect of different connectivities between pore sizes on production is studied. The effect of pore size on phase behavior is considered by using modified critical properties for different pore sizes in the phase behavior calculations. A shale gas condensate reservoir with a ternary mixture of methane (80 mol%), n-butane (10 mol%), and n-octane (10 mol%) as the reservoir fluid is modeled. The reservoir pressure and temperature are 5000 psia and 180 °F, respectively. The dew point pressure is 3600 psia. Pore sizes change between 5-150nm. Based on Scanning Electron Microscopy (SEM) studies on shale reservoir rocks, the pore volume of the reservoir was divided into five regions: bulk (stimulated area and pore sizes more than 50nm (17% PV)), 20-50nm (4% of PV), 15-20nm (6% of PV), 10-15nm (45% of PV), and less than 10nm (28% of PV). Three different types of connectivities between pores were considered: 1-completely random distribution 2-pore sizes from smallest to largest connected to the SRV in series, and 3-pore sizes from largest to smallest connected to the SRV in series. Our study has shown that by decreasing the pore size, dew point pressures decrease between 5 to 17%. Also by decreasing pore size, two-phase region shrinks therefore condensate drop-out and near wellbore permeability impairment are reduced. After 10 years of production, condensate saturation around SRV is 6-10% less under confinement effects. Gas and condensate viscosities under confinement decrease 3-16% and 10-45% respectively. Considering effect of confinement did not affect gas production significantly but the liquid production increased significantly and doubled. The effect of different pore size connectivities caused a 20% change in liquid productions. The results of this study can have a significant impact on our understanding of gas condensation and transport in shale formations thereby enabling improved field planning, well placement, completions design and facilities management.

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Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings. This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.

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