Wireline formation testing (WFT) is an important aspect in both exploration and production phases for reservoir evaluation. WFT tools can directly measure the formation pore pressures and then the pressure profiles are used to identify the type of pore fluids, identify the fluids density, fluid contact estimation, depletion and overpressure quantification, detection of continuity and connectivity of the reservoir in both the lateral and vertical directions. WFT is mostly used to evaluate formation permeability and taking fluid sampling. The new generation wireline formation sampling tools include a downhole fluid analyzer (DFA), which can analyze the composition of fluids in real-time and under in-situ conditions and also can measure the spectra of crude oil. So, in result, it is possible to identify fluid compositional variation and reservoir vertical compartmentalization. The analysis of fluid composition depends on the optical absorption, and the mass fraction estimation for the three groups of hydrocarbons: methane (C1), C2-5, and C6 + along with CO2 as well. Also, it provides formation fluid properties like gas oil ratio (GOR), density, viscosity, and resistivity. The DFA results are subsequently validated and modified by laboratory analysis on the fluid samples attained from the formation. The potential advantage of early measurements demonstrates that the DFA is a good decision-making solution in early stage without waiting for the lab result for months. Also, early DFA measurements are important in completion designing and well testing, the establishment of fluid gradients in reservoirs and connectivity, identifying and validating fluid distributions and reservoir structures.

Shale gas reservoirs may contain pores with different origins (; natural or induced) and scales. They can be divided into four groups, inorganic porosity, organic porosity, natural micro-fractures porosity and artificially created fractures porosity. The inorganic porosity is the void spaces within matrix of clay, pyrite, silica and other non-organic minerals. The organic porosity is the void space that remains in organic matter after conversion the kerogen to gas and oil. Organic matter in the form of kerogen is finely dispersed within inorganic matrix and contain void spaces (organic porosity). Micro-fractures network contains void spaces (natural micro-fractures porosity) and pore network system is also formed after creation of hydraulically induced fractures (artificially created fractures porosity). Simulating gas production from shale gas is a complex process due to interaction of fluid with various pore scales. In the current research work, shale gas transport through complex porous network is reviewed. Transport mechanism for free and adsorbed gas in dispersed organic nano-pores is combination of both Darcy and non-Darcy phenomena. Slippage of gas molecules occurs in organic pores and desorption of gas molecules occurs as the reservoir pressure depletes. The combined flux from organic pores is transported into inorganic pores then transported into micro-fractures network which can be exploited if hydraulically induced fractures are created in the vicinity of wellbore. It is a huge challenge to model gas production from shales due to presence of multi-scaled porosities. Slippage effects and desorption further add to the complexity in shale gas reservoirs. Analytical models, presented in the current review paper, incorporate complexities in shale gas reservoirs so that production from shale gas can be modeled precisely.