It is common practice to use PVT data measured in laboratories (i.e. bulk fluid properties) for reservoir modeling and production data analysis purposes. However, theoretical studies have shown that fluid properties (including critical properties, phase behavior, viscosity, density, etc.) change under nano-scale confinement in shale reservoirs due to the abundance of interactions between the fluid molecules and the pore walls (pore proximity effects). In addition to these effects, in nanopores, an adsorbed layer can form which could cause changes in the apparent permeability to the free gas phase. The purpose of this study therefore is to incorporate the effects of pore proximity and adsorbed layer thickness changes into rate-transient analysis. The transient linear flow period in particular is studied for this purpose as it is often the dominant flow period in shale gas wells.

An iterative integral method is used to solve the nonlinear partial differential equation (PDE) for fluid flow in the presence of pore proximity effects and changing adsorbed layer thickness. Fluid properties (i.e. viscosity and density) under confinement are simulated using critical property adjustments and conventional fluid property correlations. The simplified local density model is used to estimate the thickness of the adsorbed layer, and this is coupled with an apparent permeability equation, which accounts for diffusion and slippage phenomena, to quantify permeability alteration in the presence of an adsorbed layer. Stress-sensitivity of permeability is also accounted for.

The results of our analysis using simulated data show that neglecting proximity effects in linear flow analysis leads to overestimation of the linear flow parameter ( i.exfki) in nanoporous shale reservoirs. This in turn could cause errors in the derivation of fracture half-length, if permeability is known, or vice-versa.

The new modified analytical rate-transient analysis tools and procedures provided in this work will lead to improved linear flow analysis, should pore proximity and confinement effects be important. In general, this method can be used for inclusion of different pressure-dependent fluid and rock properties and processes in the analysis of shale gas reservoirs.

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