Search

CO2 injection into shale reservoirs has been recently proposed as a promising method that can be used to enhance hydrocarbon recovery from shale reservoirs. Adsorption behavior of hydrocarbon(s)/CO2 mixtures under shale-reservoir conditions plays an important role in affecting the efficiency of CO2-enhanced hydrocarbon recovery from shale. In organic pores residing in shale reservoirs, the adsorption behavior of hydrocarbon(s)/CO2 mixtures can be significantly affected by the strong fluid/pore-wall interactions. In this work, a double-nanopore system comprising of two pores with sizes of 1 nm and 3 nm is built; then the competitive adsorption behavior of hydrocarbon(s)/CO2 mixtures (i.e., C1/nC4, C1/CO2, nC4/CO2, and C1/nC4/CO2 mixtures) is investigated in this double-nanopore system using the molecular dynamic (MD) simulations. Firstly, the competitive adsorption behavior of C1/nC4 mixture in double-nanopore system is studied with a depressurization manner. The effects of pressure and pore size distribution on competitive adsorption between hydrocarbons and CO2 are discussed. To investigate the efficiency of CO2 in replacing C1 or nC4 molecules from organic pores, dynamic distribution characteristics of C1/CO2, nC4/CO2, and C1/nC4/CO2 mixtures in the double-nanopore system are further investigated. The competitive adsorption behavior of C1/nC4 mixture indicates that, in both nanopores, as pressure decreases, adsorption of lighter hydrocarbon (i.e., C1) decreases significantly, but adsorption of heavier component (i.e., nC4) increases slightly. It suggests that as pressure decreases, the lighter hydrocarbons can be easily extracted from nanopores, while the heavier hydrocarbons may not be readily produced. Adsorption behavior of C1/CO2 indicates that CO2 can help the C1 recovery from nanopores; meanwhile, the recovery efficiency in the larger pore, (i.e., 3 nm), is much higher than that in the smaller pore (i.e., 1 nm). On the contrary, as pressure decreases, adsorption of nC4 in nC4/CO2mixtures in both nanopores is becoming stronger with the presence of CO2; the same behavior is also observed for C1/nC4/CO2 mixture. This implies that, although CO2 injection may help the recovery of lighter hydrocarbons (e.g., C1), but may not be an efficient agent for the recovery of heavier hydrocarbons (e.g., nC4).

Three-phase vapor-liquid-aqueous (VLA) equilibria can frequently appear in hydrocarbon reservoirs. The presence of the aqueous phase, which can commonly exist as a pure water phase, can dramatically increase the probability of encountering convergence issues in the three-phase equilibrium calculation algorithms. The primary reason is that there is a lack of good initial estimates of equilibrium ratios in both stability tests and flash calculations. In this research, we improve the three-phase VLA equilibrium calculation algorithm for water/hydrocarbon mixtures by developing a new scheme for initializing equilibrium ratios as well as a new procedure for three-phase equilibrium calculations. By applying this new initialization scheme, one can securely identify the aqueous-like stationary point on the tangent plane distance function. In our algorithm, convergence problems, which can frequently appear in the flash calculations of three-phase VLA equilibrium calculations, are avoided. We demonstrate the robustness and efficiency of the newly developed algorithm by showing a number of example calculations.

Accurate description of absolute adsorption/desorption behavior for hydrocarbons on shale is of critical importance to the understanding of the fundamental mechanisms governing the storage, transport, and recovery of shale gas or shale gas condensate in shale reservoirs. By applying a thermogravimetric method, we first measure the excess adsorption/desorption isotherms of pure CH4 and n-C4H10 on shale samples over the temperature range of 303.15–393.15 K. The maximum test pressures considered for CH4 and n-C4H10 are 50 bar and 2 bar, respectively. Grand Canonical Monte Carlo (GCMC) simulations are then applied to calculate the density of the adsorption phase by considering the fluid-pore surface interactions. We use such calculated density of the adsorption phase to calibrate the excess adsorption/desorption isotherms, which enables us to eventually obtain the absolute adsorption/desorption isotherms. Such approach for estimating the density of the adsorption phase is essentially different from the commonly used approaches in which the density of the adsorption phase is considered to be independent of temperature, pressure, and pore size. The adsorption/desorption test results show that both CH4 and n-C4H10 exhibit more adsorption as temperature decreases or pressure increases. Their adsorption/desorption isotherms exhibit hysteresis phenomenon and this phenomenon weakens as temperature increases. Comparatively, the hysteresis behavior observed for n-C4H10 is more obvious than that for CH4. Compared with CH4, n-C4H10 has higher adsorption capacity under the same condition, indicating its higher affinity towards the shale with organic matters. As for the conventional approaches, the density calculated from the van der Waals constant b or the liquid hydrocarbon density can be used to reasonably well evaluate the absolute adsorption isotherms of n-C4H10 on shale, but tends to underestimate the absolute adsorption of CH4 on shale. GCMC simulations show that the density of the adsorption phase is strongly correlated with system pressure, temperature, and pore size. Compared to the conventional approaches, GCMC simulations can better capture the in-situ density of adsorption phase; on the basis of the in-situ density of adsorption phase, we can then achieve more accurate determination of the absolute adsorption isotherms of a given hydrocarbon on shale. This study raises the imperativeness of leveraging more sophisticated simulation tools (such as GCMC) for more accurate determination of absolute adsorption isotherms.

Conventional production optimization for waterflooding reservoirs relies on full-scale reservoir simulators and repeated simulation runs to calulate gradient information. These factors lead to expensive computational cost. Different from the conventional optimization, in this paper, a novel waterflooding optimization method is developed by running a data-driven interwell numerical simulation model with flow-path tracking (INSIM-FPT) in three dimensions. With the application of flow-path tracking strategy, the more-accurate calculations of dynamic allocation factors and control pore volumes can be obtained from INSIM-FT-3D model. Moreover, based on the INSIM model, we define producer-centered production efficiency of wells with multiple perforations and propose a rapid waterflooding optimization method. The optimized well production rates and injection rates are obtained with the help of the oil cut and the existing injector-centered allocation factors derived from INSIM model. The new optimization method requires only one time forward run without repeated iterative calculations. And the optimization is completely based on reservoir-engineering points of view, making it easy to explain oil increment mechanisms. Finally, a synthetic case and the other large-scale field case is established to test its optimization performance.