No abstract

[1] Carbon dioxide (CO 2 ) is often used for enhanced oil recovery in depleted petroleum reservoirs, and its behavior in rock is also of interest in CO 2 capture and storage projects. CO 2 usually becomes supercritical (SC-CO 2 ) at depths greater than 1,000 m, while it is liquid (L-CO 2 ) at low temperatures. The viscosity of L-CO 2 is one order lower than that of normal liquid water, and that of SC-CO 2 is much lower still. To clarify fracture behavior induced with injection of the low viscosity fluids, we conducted hydraulic fracturing experiments using 17 cm cubic granite blocks. The AE sources with the SC-and L-CO 2 injections tend to distribute in a larger area than those with water injection, and furthermore, SC-CO 2 tended to generate cracks extending more three dimensionally rather than along a flat plane than L-CO 2 . It was also found that the breakdown pressures for SC-and L-CO2 injections are expected to be considerably lower than for water.

Molecular dynamic simulations were performed to determine the elastic constants of carbon dioxide (CO2) and methane (CH4) hydrates at one hundred pressure–temperature data points, respectively. The conditions represent marine sediments and permafrost zones where gas hydrates occur. The shear modulus and Young’s modulus of the CO2 hydrate increase anomalously with increasing temperature, whereas those of the CH4 hydrate decrease regularly with increase in temperature. We ascribe this anomaly to the kinetic behavior of the linear CO2 molecule, especially those in the small cages. The cavity space of the cage limits free rotational motion of the CO2 molecule at low temperature. With increase in temperature, the CO2 molecule can rotate easily, and enhance the stability and rigidity of the CO2 hydrate. Our work provides a key database for the elastic properties of gas hydrates, and molecular insights into stability changes of CO2 hydrate from high temperature of ~5 °C to low decomposition temperature of ~−150 °C.

Based on molecular dynamics simulations of eight ions (Na, K, Rb, Cs, Mg, Ca, Sr, and Ba) on muscovite mica surfaces in water, we demonstrate that experimental data on the muscovite mica surface can be rationalized through a unified picture of adsorption structures including the hydration structure, cation heights from the muscovite surface, and state stability. These simulations enable us to categorize the inner-sphere surface complex into two different species: an inner-sphere surface complex in a ditrigonal cavity (IS1) and that on top of Al (IS2). By considering the presence of the two inner-sphere surface complexes, the experimental finding that the heights of adsorbed cations from the muscovite surface are proportional to the ionic radius for K and Cs but inversely proportional to the ionic radius for Ca and Ba was explained. We find that Na, Ca, Sr, and Ba can form both IS1 and IS2; K, Rb, and Cs can form only IS1; and Mg can form only IS2. It is suggested that the formation of IS1 and IS2 is governed by the charge density of the ions. Among the eight ions, we also find that the hydration structure for the outer-sphere surface complexes of divalent cations differs from that of the monovalent cations by one adsorbed water molecule (i.e., a water molecule located in a ditrigonal cavity).

With the development of atomic force microscopy (AFM), it is now possible to detect the buried liquid-solid interfacial structure in three dimensions at the atomic scale. One of the model surfaces used for AFM is the muscovite surface because it is atomically flat after cleavage along the basal plane. Although it is considered that force profiles obtained by AFM reflect the interfacial structures (e.g., muscovite surface and water structure), the force profiles are not straightforward because of the lack of a quantitative relationship between the force and the interfacial structure. In the present study, molecular dynamics simulations were performed to investigate the relationship between the muscovite-water interfacial structure and the measured AFM force using a capped carbon nanotube (CNT) AFM tip. We provide divided force profiles, where the force contributions from each water layer at the interface are shown. They reveal that the first hydration layer is dominant in the total force from water even after destruction of the layer. Moreover, the lateral structure of the first hydration layer transcribes the muscovite surface structure. It resembles the experimentally resolved surface structure of muscovite in previous AFM studies. The local density profile of water between the tip and the surface provides further insight into the relationship between the water structure and the detected force structure. The detected force structure reflects the basic features of the atomic structure for the local hydration layers. However, details including the peak-peak distance in the force profile (force-distance curve) differ from those in the density profile (density-distance curve) because of disturbance by the tip.

Summary Digital oil, a realistic molecular model of crude oil for a target reservoir, opens a new door to understand properties of crude oil under a wide range of thermodynamic conditions. In this study, we constructed a digital oil to model a light crude oil using analytical experiments after separating the light crude oil into gas, light and heavy fractions, and asphaltenes. The gas and light fractions were analyzed by gas chromatography (GC), and 105 kinds of molecules, including normal alkanes, isoalkanes, naphthenes, alkylbenzenes, and polyaromatics (with a maximum of three aromatic rings), were directly identified. The heavy fraction and asphaltenes were analyzed by elemental analysis, molecular-weight (MW) measurement with gel-permeation chromatography (GPC), and hydrogen and carbon nuclear-magnetic-resonance (NMR) spectroscopy, and represented by the quantitative molecular-representation method, which provides a mixture model imitating distributions of the crude-oil sample. Because of the low weight concentration of asphaltenes in the light crude oil (approximately 0.1 wt%), the digital oil model was constructed by mixing the gas, light-, and heavy-fraction models. To confirm the validity of the digital oil, density and viscosity were calculated over a wide range of pressures at the reservoir temperature by molecular-dynamics (MD) simulations. Because only experimental data for the liquid phase were available, we predicted the liquid components of the digital oil at pressures lower than 16.3 MPa (i.e., the bubblepoint pressure) by flash calculation, and calculated the liquid density by MD simulation. The calculated densities coincided with the experimental values at all pressures in the range from 0.1 to 29.5 MPa. We calculated the viscosity of the liquid phase at the same pressures by two independent methods. The calculated viscosities were in good agreement with each other. Moreover, the viscosity change with pressure was consistent with the experimental data. As a step for application of digital oil to predict asphaltene-precipitation risk, we calculated dimerization free energy of asphaltenes (which we regarded as asphaltene self-association energy) in the digital oil at the reservoir condition, using MD simulation with the umbrella sampling method. The calculated value is consistent with reported values used in phase-equilibrium calculation. Digital oil is a powerful tool to help us understand mechanisms of molecular-scale phenomena in oil reservoirs and solve problems in the upstream and downstream petroleum industry.

By using molecular dynamics (MD) simulations and potential of mean force (PMF) calculations, we studied the stability of model acidic oil molecules (C 9 H 19 COOH or C 9 H 19 COO − ) adsorbed on muscovite surfaces in aqueous solution. The muscovite surfaces are covered by different cations (Na + , K + , Mg 2+ , and Ca 2+ ). It was found that Ca 2+covered muscovite surface significantly enhances the adsorption of C 9 H 19 COO − with adsorption Gibbs energy 1 order of magnitude higher than that of Na + -covered surface and 3 times higher than that of K + -covered surface. Furthermore, we found clear evidence that Ca 2+ and K + cause cation bridging, whereas Mg 2+ and Na + cause water bridging. The adsorption Gibbs energy is much higher for cation bridging than that of water bridging. The ion specific effect is not observed when the carboxyl group is protonated (i.e., C 9 H 19 COOH). These results well explain the results of previous wettability and core flooding experiments and support their key findings that adsorption of Ca 2+ cations induces a macroscopic wetting transition either on a flat mineral surface (in wettability experiments) or in a porous media (in core flooding experiments). The insight obtained in this study leads us to optimal design of low-salinity water flooding for enhanced oil recovery.

Summary Slip phenomenon is one of the major characteristics of gas flow through porous media—in particular, in unconventional gas reservoirs with small pore throats, such as tight sands, coal seams, and shale formations. Consequently, a permeability correction needs to be considered to evaluate the gas-flow ability in these reservoirs. Various analytically derived and empirical correction models exist for engineering applications. However, it is not well-understood which one should be implemented in real-shale-reservoir problems. In this paper, slip velocity and permeability for gas flow in nanopores are studied by molecular-dynamics (MD) simulations. For simplicity, the system considered is methane gas flow in a parallel-plate channel of quartz and kerogen. The fluid flow is characterized by the Knudsen number (Kn), which is defined as the ratio between the mean free path and the representative length of the pores. Studies with various Knudsen numbers were conducted by changing (1) the methane density (the mean free path) or (2) the plate-spacing (pore size). Simulation results show that the relationships between slip velocity and Knudsen number and between the permeability-correction factors and Knudsen number agree well with the Beskok and Karniadakis (1994) analytical solution (BK model) for large nanopores (12–34 nm) in both quartz and kerogen cases. This model considered rarefaction and compressibility effects on gas microflows, and was tested experimentally with characteristic dimensions of one-micrometer order. Our simulation results indicate that this model can be extended to nanoflows existing in unconventional reservoirs. Under temperature and pressure conditions that we studied, deviation from the BK model is noted for small nanopores (<12 nm), but for a pore size smaller than 6 nm, it converges to a constant value in the quartz slit pore. In contrast, a radical increase of slip velocity is observed in the kerogen pore. The deviation from the BK model for a pore size smaller than 12 nm is ascribed to the fact that the overall fluid is no longer homogeneous (i.e., the fluid at the interface region plays a crucial role in the overall flow behavior). An adsorption structure is observed in the proximity of the solid walls because of the interaction from the wall molecules. Moreover, it is found that the effect of roughness becomes significant in an extremely small kerogen nanopore.