A pore-network-based upscaling framework for the nanoconfined phase behavior in shale rocks

The viability of miscible WAG injection as an EOR scheme for the Magnus reservoir is under consideration. Performance prediction and optimization under this type of recovery mechanism, in which the residual oil is usually recovered by a multi-contact miscible (MCM) process, rely mostly upon compositional simulation. Unfortunately, numerical dispersion effects, associated with large grid blocks required in field scale compositional simulation of MCM processes, can result in erroneous phase behavior. Reduction of dispersion to acceptable levels may require very small grid blocks, implying model sizes that exceed the capacity of current conventional computer installations. Thus, full field compositional models are not practical for reliable field-wide benefit predictions. This paper presents a systematic procedure that we successfully employed for prediction of field wide performance and recovery benefit of miscible WAG injection for the Magnus reservoir. The procedure involves an extension of the upscaling technique proposed by Fayers et al [1]. It starts with a 3D fine grid compositional sector model of a small representative element of the reservoir. Then, this reference model is upscaled to block sizes corresponding to those in the Magnus full field model (FFM), using the single-phase half-cell upscaling technique. The upscaled model employs the Todd and Longstaff (T&L) formulation [1,2] for simulating MCM displacement and three-pseudo components for representing phase behavior. The PVT, solvent equilibrium constants and miscibility pressure vs. composition tables are developed through matching with a calibrated 12-component equation of state (EOS) and 1D slim tube simulations, for a wide range of pressure and composition. The PVT treatment also allows for vaporization of oil by the contacting gas. To calibrate the model, the upscaled transmissibility values had to be further adjusted in order to match the reference single-phase pressure/rate performance for several horizontal and vertical flow orientations. The base waterflood performance matching was achieved for a couple of potential well orientations by adjusting water-oil relative permeability curves. The final stage involved determining the T&L mixing parameters through calibration of MCM WAG displacement performance with the reference fine grid compositional model. This approach led to a set of T&L mixing parameters, which result in a very encouraging match between the upscaled and the reference model. Calculated WAG recovery is more sensitive to the viscosity rather than density mixing parameter, indicating a moderate tendency for gas gravity override. Further sensitivities were performed to examine the robustness of the calibrated upscaled model against variations in operating parameters. The results confirm that the upscaled model satisfactorily matches the reference model in terms of variations of the benefit with slug size and WAG ratio. The determined T&L mixing parameters were then implemented with confidence in the Magnus T&L FFM for predictions of field-wide MCM WAG benefit, returned gas (injected gas produced) volume and composition, and water and gas lift gas requirements post EOR. We also discuss impacts of various uncertain parameters on the performance of MCM WAG injection, which were investigated using the calibrated upscaled model, taking advantage of about 1000 times gain in CPU time compared to that for the reference fine grid compositional model.

CO2 injection into an oil reservoir at low temperatures (less than 120 °F) can form three hydrocarbon phases, i.e. a vapor phase, an oil-rich liquid and a CO2-rich liquid phase. Most available reservoir simulators cannot handle three-hydrocarbon-phase flash, and the use of two-phase flash may cause significant numerical instability. The issue has been recognized in the industry for a long time. Studies to include three-hydrocarbon-phase flash in compositional simulations exist in the literature. However, this approach results in substantial increases of model complexity and computational cost, thus it may not be realistic for practical applications (at least for now). In this work, we propose a new PVT modeling procedure to eliminate the three-hydrocarbon-phase region for reservoir fluid/CO2 mixtures at low temperatures, and study its implication on flow simulation. In our method, the acentric factors of pseudo-components are adjusted to eliminate the three-hydrocarbon-phase region, which was not considered in any of the previous studies. Then, the experimental data for reservoir fluid PVT, CO2 swelling test, and MMP are also matched by further adjusting binary interaction coefficients, volume shift parameters and critical volumes of the pseudo-components. The procedure is applicable for cases with relatively small three-phase regions (e.g., some fields in west Texas), and can be applied with any PVT simulation software, and conventional two-hydrocarbon-phase simulators. The method is considered for two sector models from oil fields in west Texas, with fine-scale (more than 600,000 grid blocks) and up-scaled models. Compared to the standard characterization, in which the three-hydrocarbon phases exist, the new fluid model significantly improves the stability of flow simulation, demonstrating the robustness and efficiency of the new procedure. The method can be viewed as a practical approximation to field-scale simulations of the CO2 injection at low temperatures.

Predicting microemulsion phase behavior using physics based HLD-NAC equation of state for surfactant flooding

Carbon dioxide transport will be a key part of any Carbon Capture and Storage (CCS) system. Generally for CCS, flow assurance modeling of these pipelines has been restricted to pure CO2 systems; however CO2 streams coming from capture processes are not pure and contain various components. These fluids have a certain level of moisture, so dehydration is needed before delivering CO2 rich fluid to the export pipeline, in order to prevent potential hydrate formation, two-phase flow and corrosion in the export line. In this contribution, the hydrate phase equilibria of the binary CO2 + (N2 or CH4 or O2 or Ar or CO) systems in the presence of a free water phase were determined as well as direct hydrate dissociation conditions of liquid CO2 in absence of a free phase. A rigorous and generalized model is presented to predict the phase behavior, hydrate dissociation pressures and the dehydration requirements of CO2 rich gases. A statistical thermodynamic approach, with the Cubic-Plus-Association equation of state, is employed to model the phase equilibria. The hydrate-forming conditions are modeled by the solid solution theory of van der Waals and Platteeuw. Predictions of the developed model are first validated using simple systems and then for more complicated synthetic multicomponent systems. Showing that accurate phase behavior prediction of CO2 rich stream is critical for accurate predictions of the hydrate phase behavior of these fluids.

Structural transition and phase behavior of N2 gas hydrates with pinacolyl alcohol and tert-amyl alcohol

Flow simulation of multimillion grid cell models with hundreds of wells and decades long production history can be extremely time-consuming. This often limits the applicability of assisted history matching techniques. A pragmatic solution to this problem is grid coarsening which is now embedded in many commercial reservoir simulators. Instead of up-scaling geological models in external packages, grid cells are automatically amalgamated within the simulator while preserving flux distribution and reducing the total number of active cells. The resulting speedup can be significant, often only at small loss of accuracy. Both characteristics are essential elements of any inversion technique in a multimillion grid cell environment. For water-flood history matching, we have utilized a commercial finite-volume simulator and the streamline-based generalized travel time inversion whereby water-cut behavior is matched by adjusting inter-well permeabilities. To apply the assisted history matching technique on high resolution models, a flux reconstruction method is devised which makes full use of the benefits of automatic grid coarsening. It approximates fluxes in the original geological grid by recalculating transmissibility at the fine scale and redistributing coarse scale fluxes accordingly. The inversion is thus conducted on the fine scale grid, while the forward simulation model uses the coarse grid. While solving for an inexpensive coarse model, the calibration takes into account fine grid resolution. Upscaling is not required and the degree of coarsening can be adjusted during the matching process. The proposed method was successfully tested on a supergiant carbonate oilfield with about hundred wells and large-scale water injection. The history match improved dramatically at relatively low numerical cost, which also allowed for investigating multiple sensitivities. The results were verified against non-coarsened model. The significant increase in efficiency makes this a potential method of choice for cases, where previously assisted history matching techniques could not be deployed due to excessive run times.

Anomalous bedload transport has been widely observed in both laboratory settings and natural rivers. Previous studies have utilized the fractional advection‐diffusion equation (FADE) model to characterize the observed anomalous bedload transport behaviors, with the model's parameters being determined by the tail distributions of the probability density functions (PDFs) for particle resting times and step lengths. FADE model captures sub‐diffusion and super‐diffusion behavior resulting from the heavy‐tailed PDFs of step lengths and resting times; however, it overlooks the temporal variability of advection and diffusion coefficients throughout the transport process. This study developes a novel microscopic stochastic process that incorporates nonstationary Lévy motion. The scaling limit of the stochastic process leads to the development of a hybrid Hausdorff‐fractional model. In the upscaling model, sub‐diffusion is represented by a time‐metric transformation, while super‐diffusion is characterized by nonlocal particle movements. Applications show that the novel model serves a generalized tool to characterize anomalous bedload transport processes across various scales. The upscaling model bridges the microscopic stochastic particle dynamics and macroscopic bedload transport behavior, and the microscopic stochastic framework provides a comprehensive physical interpretation for each parameter in the macroscopic equations, thereby enhancing the understanding of collective particle dynamics.

This laboratory study describes the technical feasibility of applying CO2 miscible flooding in a major field in Abu Dhabi, UAE. The field section considered is a low permeability carbonate that had so far poorly responded to water flooding. The study had two major aspects, phase behavior and core flooding. In phase behavior, the field's petroleum was studied with its minimum miscibility pressure with CO2 determined. Also, asphaltene precipitation due to CO2 injection was measured and included in the phase behavior model. In core flooding, detailed rock characterization was carried out using SEM, EDS, and ICP. Thereafter, core floods were carried out to evaluate the additional recovery from miscible CO2 injection and the optimum CO2 slug sizes. Core floods were also used to evaluate recoveries from different initial saturations, for less than miscible conditions, and for side effects such as asphaltene precipitation, sulfur deposition, and effect of CO2 on the limestone rock.

The prediction of surfactant phase behavior has applications in a wide range of areas. An accurate modeling of liquid phase behavior can aid our understanding of colloidal process or be used to design phases that respond in a defined way to their environment. In this work, we use molecular dynamics to model the phase behavior of the ternary sodium laurate/sodium oleate/water system and compare the simulation results to experimental data. Simulations were performed with the GROMOS 53A6 united-atom force field and cover the entire ternary phase diagram, producing micellar, hexagonal, and lamellar phases. The aggregate simulation time for the 33 simulations performed during this study is 4.4 μs. We find that the simulations were able to model the experimentally observed liquid phase behavior accurately, showing that the carboxylate and lipid parameters of the 53A6 force field give very good quality results for the in silico prediction of liquid system phase behavior.

Phase-field modeling of diffusional phase behaviors of solid surfaces: A case study of phase-separating LiXFePO4 electrode particles

Critical review of microemulsion phase behavior models: benefits, research gaps, industrial challenges, and roadmap

Local quantification of mesoporous silica microspheres using multiscale electron tomography and lattice Boltzmann simulations

Alkali and donor–acceptor bridged three-dimensional interpenetrating polymer networks boost photocatalytic performance by efficient electron delocalization and charge transfer

Alkaline water electrolysis technology for hydrogen production has been successfully commercialized, yet challenges such as insufficient catalytic activity and durability persist. Herein, a novel monolithic electrode architecture (NF/Ni3Fe@NiFe-OOH) featuring a multi-scale hierarchical pore structure was designed to optimize oxygen evolution reaction (OER) kinetics. The electrode comprises three distinct structural components of a macroporous nickel foam framework, a mesoporous nickel-iron alloy nanomelt interlayer, and a microporous nickel-iron oxyhydroxide active layer, which exhibits an overpotential of 210 mV at 100 mA cm-2 and an over 140 h robust durability with 97.2% voltage retention at 50 mA cm-2 (93.2% at 300 mA cm-2). The outstanding OER performance of the sample can be primarily ascribed to the monolithic electrode featuring the multi-scale pore structures, which show significant advantages in facilitating electrolyte diffusion, electron transfer, and efficient bubble dissipation.

The possibility to model petroleum composition during hydrocarbon generation as well as the PVT behaviour of the fluids during migration has only recently become available in modern basin modelling software packages. While various compositional kinetic models of petroleum generation have been published in the past few years, none of the studies presented have attempted to match the composition, physical properties and phase state of known petroleum accumulations. Using compositional data from closed-system non-isothermal pyrolysis experiments, we developed a compositional kinetic model of hydrocarbon generation for a marine Type II source rock, which uses 13 components to describe the generated fluid. The data format selected is compatible with the compositional resolution used in reservoir engineering, thus allowing a direct comparison of predicted compositions and phase behaviour with PVT data of natural fluids. Compositional predictions of the model were tuned to a well-documented maturity sequence from the Tampen Spur, Norway, and the calibrated model implemented in a 2D basin modelling study of the Snorre Field, Norway. The results of the modelling led to an excellent correlation between predicted and reported reservoir fluid properties (formation volume factor, GOR and saturation pressure) for the present-day situation. The results indicate that the Snorre reservoir has received a continuous charge since the late Cretaceous-early Tertiary and that it most likely contained a two-phase system prior to the latest Plio-Pleistocene burial and overpressuring event.