Search

A model for shale gas flow in a fractal dual-porosity rock is built and well validated with experimental data. Results indicate that (1) the gas transport in shale natural fractures gradually becomes a higher priority in the dual-porosity rock with the increase of fracture porosity; (2) the ratio of minimum fracture aperture to a fracture aperture and the fractal dimension of fracture together contribute to the fracture aperture distribution. More fractures with larger aperture exist in shale rock with larger minimum fracture aperture, which benefits gas apparent permeability; (3) a natural fracture-dominant region enlarges with decreasing fractal dimension of fracture aperture and increasing minimum fracture aperture, and this is beneficial to the improvement of the gas apparent permeability. [ABSTRACT FROM AUTHOR]

Understanding and controlling the flow of water confined in nanopores has tremendous implications in theoretical studies and industrial applications. Here, we propose a simple model for the confined water flow based on the concept of effective slip, which is a linear sum of true slip, depending on a contact angle, and apparent slip, caused by a spatial variation of the confined water viscosity as a function of wettability as well as the nanopore dimension. Results from this model show that the flow capacity of confined water is 10−1∼107 times that calculated by the no-slip Hagen–Poiseuille equation for nanopores with various contact angles and dimensions, in agreement with the majority of 53 different study cases from the literature. This work further sheds light on a controversy over an increase or decrease in flow capacity from molecular dynamics simulations and experiments. [ABSTRACT FROM AUTHOR]

Surface diffusion plays a key role in gas mass transfer due to the majority of adsorbed gas within abundant nanopores of organic matter in shale gas reservoirs. Surface diffusion simulation is very complex as a result of high reservoir pressure, surface heterogeneity, and nonisothermal desorption in shale gas reservoirs. In this paper, a new model of surface diffusion for adsorbed gas in shale gas reservoirs is established, which is based on a Hwang model derived under a low pressure condition and considers the effect of adsorbed gas coverage under high pressure. Additionally, this new model considers the effects of surface heterogeneity, isosteric sorption heat, and nonisothermal gas desorption. Results show that (1) the surface diffusion coefficient increases with pressure and temperature, while it decreases with activation energy and gas molecular weight; (2) contributions of viscous flow, Knudsen diffusion, and surface diffusion to the total gas mass transfer are varying during the development of shale gas reservoirs, which are mainly controlled by nanopore-scale and pressure; (3) in micropores (pore radius of >2 nm), the contribution of surface diffusion to the gas mass transfer is dominant, up to 92.95%; in macropores (pore radius of <50 nm), the contribution is less than 4.39%, which is negligible; in mesopores (2 nm > pore radius > 50 nm), the contribution is between micropores and macropores. [ABSTRACT FROM AUTHOR]

Gas flow properties in nanopores are significantly determined by the flow patterns. Slug flow pattern is a potential wateregas two phase flow pattern, in which gas molecules flow in form of gas slugs and water molecules separate gas slugs. Considering water slippage, a portion of water molecules accumulates at the wall with lower mobility, while the remaining water molecules take the shape of a water bridge. Adopting foam apparent viscosity model to represent slug rheological behavior, how water bridge disturbs on gas flow capacity is estimated. The results are compared with the wateregas two phase flow model that assumes annular flow pattern as well as the single gas flow model without the consideration of water. The comparison illustrates that gas molecular movement is significantly hindered by flow space reduction and loss of gas slippage. The impact from water phase of slug flow pattern is more significant than that of annular flow pattern on gas flow capacity. It is discovered that larger nanopores improve gas flow capacity while maintaining bulk water layer thickness and increasing water bridge thickness tend to reduce gas transport ability. A better understanding of the structure and transport of water and gas molecules is conducive to figure out the specific gasewater flow behavior and predict shale gas production. [ABSTRACT FROM AUTHOR]

Previous attempts to characterize the gas transport through inorganic nanopores were not fully successful. The presence of an adsorption water film within nanopores is generally overlooked. Moreover, the compound influences of moisture content and confinement effect on critical properties of the gas phase have not been considered before. With the intent of overcoming these deficiencies, a fully coupled analytical model has been developed, in which complex bulk-gas transport mechanisms, moisture content, confinement effect, and various cross-section shapes of nanopores are incorporated. Results show that the confinement effect will significantly enhance the apparent gas permeability when the pore radius is smaller than 5 nm, and the real-gas effect can achieve an average increase of 4.38% when the pore radius falls in the range 1–2 nm. The stress dependence will greatly decrease the apparent gas permeability and the corresponding degree for slitlike inorganic nanopores will slightly increase with the increasing aspect ratio. [ABSTRACT FROM AUTHOR]

In the Pikes Peak oil field near Lloydminster, Canada, a significant amount of heavy oil reserves is located in reservoirs with a bottom water zone. The properties of the bottom water zone and the operation parameters significantly affect oil production performance via the steam-assisted gravity drainage (SAGD) process. Thus, in order to develop this type of heavy oil resource, a full understanding of the effects of these properties is necessary. In this study, the numerical simulation approach was applied to study the effects of properties in the bottom water zone in the SAGD process, such as the initial gas oil ratio, the thickness of the reservoir, and oil saturation of the bottom water zone. In addition, some operation parameters were studied including the injection pressure, the SAGD well pair location, and five different well patterns: (1) two corner wells, (2) triple wells, (3) downhole water sink well, (4) vertical injectors with a horizontal producer, and (5) fishbone well. The numerical simulation results suggest that the properties of the bottom water zone affect production performance extremely. First, both positive and negative effects were observed when solution gas exists in the heavy oil. Second, a logarithmical relationship was investigated between the bottom water production ratio and the thickness of the bottom water zone. Third, a non-linear relation was obtained between the oil recovery factor and oil saturation in the bottom water zone, and a peak oil recovery was achieved at the oil saturation rate of 30% in the bottom water zone. Furthermore, the operation parameters affected the heavy oil production performance. Comparison of the well patterns showed that the two corner wells and the triple wells patterns obtained the highest oil recovery factors of 74.71% and 77.19%, respectively, which are almost twice the oil recovery factors gained in the conventional SAGD process (47.84%). This indicates that the optimized SAGD process with the two corner wells and the triple wells pattern is able to improve SAGD production performance in a heavy oil reservoir with a bottom water zone. [ABSTRACT FROM AUTHOR]

In this paper, physical experiments and numerical simulations were applied to systematically investigate the non-Newtonian flow characteristics of heavy oil in porous media. Rheological experiments were carried out to determine the rheology of heavy oil. Threshold pressure gradient (TPG) measurement experiments performed by a new micro-flow method and flow experiments were conducted to study the effect of viscosity, permeability and mobility on the flow characteristics of heavy oil. An in-house developed novel simulator considering the non-Newtonian flow was designed based on the experimental investigations. The results from the physical experiments indicated that heavy oil was a Bingham fluid with non-Newtonian flow characteristics, and its viscosity-temperature relationship conformed to the Arrhenius equation. Its viscosity decreased with an increase in temperature and a decrease in asphaltene content. The TPG measurement experiments was impacted by the flow rate, and its critical flow rate was 0.003 mL/min. The TPG decreased as the viscosity decreased or the permeability increased and had a power-law relationship with mobility. In addition, the critical viscosity had a range of 42-54 mPa·s, above which the TPG existed for a given permeability. The validation of the designed simulator was positive and acceptable when compared to the simulation results run in ECLIPSE V2013.1 and Computer Modelling Group (CMG) V2012 software as well as when compared to the results obtained during physical experiments. The difference between 0.0005 and 0.0750 MPa/m in the TPG showed a decrease of 11.55% in the oil recovery based on the simulation results, which demonstrated the largely adverse impact the TPG had on heavy oil production. [ABSTRACT FROM AUTHOR]

Because of the effect of nanoscale confinement, the phase behavior of fluids confined in nanopores differs significantly from that observed in a PVT cell. In this paper, the cubic Peng-Robinson equation of state (EOS) is coupled with capillary pressure equation and adsorption theory to investigate and represent the phase equilibria of pure components and their mixtures in cylindrical nanopores. The shift of critical properties is also taken into account. Because of the effect of an adsorption film, an improved Young-Laplace equation is adopted to simulate capillarity instead of the conventional equation. For the adsorption behavior, the experimental data of the adsorbent of silicalite are used to represent the adsorption behavior of hydrocarbons in nanopores. Then a prediction process for the behavior of methane, n-butane, n-pentane, n-hexane and their mixtures are performed. Furthermore, the results are compared against the available experimental data to validate the accuracy of this scheme. An actual Eagle Ford oil is also used to examine the performance of our scheme. Results indicate that the presence of an adsorption film can further increase the vapor-liquid equilibrium constant (K-value) and capillary pressure of the confined pure-component fluid, especially in the nanopores with a few nanometers. The smaller the nanopore radius, the higher the deviation between the actual K-value and the estimated value. The capillary pressure presents a bilinear relationship with the pore radius in a log-log plot. For a binary mixture, it is observed the higher the difference between the two components, the stronger the nanopore confinement effects. For a multicomponent mixture and the real Eagle Ford oil, as the pore radius reduces, the bubble point pressure is depressed and the dew point pressure is increased. When the adsorption film is neglected, the bubble point pressure is overestimated, and the dew point pressure is underestimated. For the Eagle Ford oil, when the nanopore radius is higher than about 100 nm, the behavior approaches the bulk value and the influence of nanopore confinement can be neglected. The depression of bubble point pressure of an Eagle Ford oil reservoir well explains the behavior of a long-lasting flat producing gas/oil ratio (GOR). The phase behavior of tight oil plays an important role in reserve evaluation and development process of tight oil reservoirs. This study will shed some important insights on the phase behavior of tight oil in nanopores. [ABSTRACT FROM AUTHOR]

Molecular dynamics (MD) simulations is currently the most popular and credible tool to model water flow in nanoscale where the conventional continuum equations break down due to the dominance of fluid-surface interactions. However, current MD simulations are computationally challenging for the water flow in complex tube geometries or a network of nanopores, e.g., membrane, shale matrix, and aquaporins. We present a novel mesoscopic lattice Boltzmann method (LBM) for capturing fluctuated density distribution and a nonparabolic velocity profile of water flow through nanochannels. We incorporated molecular interactions between water and the solid inner wall into LBM formulations. Details of the molecular interactions were translated into true and apparent slippage, which were both correlated to the surface wettability, e.g., contact angle. Our proposed LBM was tested against 47 published cases of water flow through infinite-length nanochannels made of different materials and dimensions flow rates as high as seven orders of magnitude when compared with predictions of the classical no-slip Hagen-Poiseuille (HP) flow. Using the developed LBM model, we also studied water flow through finite-length nanochannels with tube entrance and exit effects. Results were found to be in good agreement with 44 published finite-length cases in the literature. The proposed LBM model is nearly as accurate as MD simulations for a nanochannel, while being computationally efficient enough to allow implications for much larger and more complex geometrical nanostructures. [ABSTRACT FROM AUTHOR]