Multi-Scale Reserve Estimation of Shale Plays
Authors: Pang Wei , Zhang Tongyi , Feng Jiangpeng , Ke Ke , Akkutlu I. Yucel 
Published: February 2020

Source rocks, such as, organic-rich shale formations have multi-scale pore structure with nano-scale features contributing to hydrocarbons storage. These hydrocarbons are divided across the organic nanopore size distribution of the source rock into fluids with altered properties. This alteration in organic nanopores is a due to multi-component hydrocarbon fluid with a significant compositional change. The smaller the pores are, the heavier the hydrocarbons in the pores become bottom. During production, nanopores release mainly the lighter end of the mixture. Hence, the composition inside the pores becomes even heavier, top. The viscosity and apparent molecular weight of the hydrocarbon mixture left behind increase significantly during the depletion . Capillary condensation of the fluid could develop in the smaller end of the nanopores depending on the thermodynamic conditions, i.e., composition, pressure and temperature. When develops, the capillary condensation resists and, hence the vaporization is avoided, even when the depletion pressure is reduced down to the pressure of vaporization, i.e., bubble point pressure. The average mean-free path length of the mixture molecules is also influenced by the nanopores in an unpredictive way . The path length values stay steady and may even decrease in small nanopores due to the capillary condensed phase occurence. The so-called nano-confinement effects significantly limit the release of hydrocarbons from the source rock organic matter, in particularly from those pores with sizes smaller than 10nm.
GCMC simulations showing fluid composition variation of hydrocarbons in nano-scale pores at various reservoir pressure. Composition data is normalized using the fluid composition outside of the nanopore. TOP: Composition variation in 4nm pore with changing reservoir pressure. BOTTOM: Composition variation in various pores at 2,000psi reservoir pressure.
Viscosity of the fluids in nanopores. The viscosity is computed using non-equilibrium periodic-shear-flow method. The computed viscosity values are normalized using the bulk fluid viscosity at the same pressure and temperature. The results show significant increase in viscosity in pores with sizes less than 5nm.
Knudsen number estimated using the trajectories of the hydrocarbon molecules in nanopores from molecular simulations. Left: Kn with varying pressure in 4.4 nm pore. Right: Kn with varying pores size at 2,000 psi.
The heavier fluid composition in the organic nanopores leads to stunning new results for the mixtures Knudsen numbers (Kn) . Based on the kinetic theory calculation with pure methane, we would have anticipated that the flow regime should change from slip to transition occurs in nano-pores and at low-pressure condition. In contrast, Kn for the confined fluids remains unchanged in the same conditions. Because the mixture in nano-pores and at low pressure is heavier and this leads to a significant reduction in the mean free path length. The pressure effect, on the right, due to the depressurization is compensated by the changes in the composition. The pressure increases the inter-molecular spacing among the molecules and, hence, lowers the chance for a collision, but the compositional changes increase the chance for collision. Thus the, compositional variation in the nanopore during depressurization compensates for this pressure effect. Eventually, the effective mean free path of the hydrocarbon fluids shows a somewhat constant value for the fluid mixtures innanopores. The results also indicate that we can describe the transport of fluids in the source rocks using continuum mechanics theory.
Based on these microscopic-level discussions, the concept of composition redistribution of the produced fluids into naopores is introduced by Akkutlu et al. (2017). This concept is crucial for the organic-rich source rock resource assessment. The hydrocarbon in-place calculations, the reserve calculations, the cut-off value for the effective porosity associated with trapped and mobile fluids, the fluid flow regimes considerations, reservoir flow simulation studies are all influenced by the redistributed composition in the nanopore size distribution. Otherwise, there will be added uncertainties in the reserve estimation.
shows the composition redistribution of the produced fluids. The reservoir engineering studies require that the composition of the fluids gathered together from the separator must be recombined to the so-called well stream fluid composition for the subsequent reservoir analyses. The recombination calculations can be performed using correlations developed for two-stage and three-stage separators. . Recombination calculations are carried out by estimating the recombined composition or specific gravity of the flowing well stream fluid from either the composition (yi, xi) or the specific gravity values (Γg, Γo) of the produced gas and liquid. The recombined data is then used for the prediction of the fluid properties, the equation of state and the liquid-vapor equilibrium in the formation under the subsurface conditions using laboratory PVT measurements or empirical correlations. Note, however, that the recombined fluid data must be re-distributed back into the formation in the case of source rocks holding organic nanopores. The redistribution calculations are proposed in using grand canonical Monte Carlo molecular simulations, where the the composition in nanopore is predicted based on the fluid pressure and composition outside of the nanopores in large volume regions in the reservoir, such as micro-fractures and cracks. Their approach has led to modifications in the volumetric method of estimating hydrocarbon in-place, and the method of reservoir flow simulations for the prediction of the reserves for the source rocks.
Composition re-distribution of the produced fluids in the organic-rich source rock.