The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition

The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.

Experimental studies on influence of temperature on relative permeability curves in sandstone reservoirs

It is crucial to obtain the representative relative permeability curves for related numerical simulation and oilfield development. The influence of temperature on the relative permeability curve remains unclear. An unsteady method was adopted to investigate the influence of temperature (range from 25–130 °C) on the oil–water relative permeability curve of sandstone reservoirs in different blocks. Then, the experimental data was analyzed by using an improved Johnson–Bossler–Naumann method. Results reveal that with the increase in temperature within a certain temperature range: (1) the relative permeability of the oil and water phases increases; (2) the irreducible water saturation increases linearly, whereas the residual oil saturation decreases nonlinearly, and the oil recovery factor increases; and (3) the saturation of two equal permeability points moves to the right, and hydrophilicity becomes stronger. The findings will aid future numerical simulation studies, thus leading to the improvement of oil displacement efficiency.

Research on the Correction Method of the Capillary End Effect of the Relative Permeability Curve of the Steady State

Relative permeability curve is a key factor in describing the characteristics of multiphase flow in porous media. The steady-state method is an effective method to measure the relative permeability curve of oil and water. The capillary discontinuity at the end of the samples will cause the capillary end effect. The capillary end effect (CEE) affects the flow and retention of the fluid. If the experimental design and data interpretation fail to eliminate the impact of capillary end effects, the relative permeability curve may be wrong. This paper proposes a new stability factor method, which can quickly and accurately correct the relative permeability measured by the steady-state method. This method requires two steady-state experiments at the same proportion of injected liquid (wetting phase and non-wetting phase), and two groups of flow rates and pressure drop data are obtained. The pressure drop is corrected according to the new relationship between the pressure drop and the core length. This new relationship is summarized as a stability factor. Then the true relative permeability curve that is not affected by the capillary end effect can be obtained. The validity of the proposed method is verified against a wide range of experimental results. The results emphasize that the proposed method is effective, reliable, and accurate. The operation steps of the proposed method are simple and easy to apply.

Relative Permeability: A Critical Parameter in Numerical Simulations of Multiphase Flow in Porous Media

Effective multiphase flow and transport simulations are a critical tool for screening, selection, and operation of geological CO2 storage sites. The relative permeability curve assumed for these simulations can introduce a large source of uncertainty. It significantly impacts forecasts of all aspects of the reservoir simulation, from CO2 trapping efficiency and phase behavior to volumes of oil, water, and gas produced. Careful consideration must be given to this relationship, so a primary goal of this study is to evaluate the impacts on CO2-EOR model forecasts of a wide range of relevant relative permeability curves, from near linear to highly curved. The Farnsworth Unit (FWU) is an active CO2-EOR operation in the Texas Panhandle and the location of our study site. The Morrow ‘B’ Sandstone, a clastic formation composed of medium to coarse sands, is the target storage formation. Results indicate that uncertainty in the relative permeability curve can impart a significant impact on model predictions. Therefore, selecting an appropriate relative permeability curve for the reservoir of interest is critical for CO2-EOR model design. If measured laboratory relative permeability data are not available, it must be considered as a significant source of uncertainty.

Pore-Scale Perspective of Gas/Water Two-Phase Flow in Shale

Summary The transport behaviors of both single-phase gas and single-phase water at nanoscale deviate from the predictions of continuum flow theory. The deviation is greater and more complex when both gas and liquid flow simultaneously in a pore or network of pores. We developed a pseudopotential-based lattice Boltzmann (LB) method (LBM) to simulate gas/water two-phase flow at pore scale. A key element of this LBM is the incorporation of fluid/fluid and fluid/solid interactions that successfully capture the microscopic interactions among phases. To calibrate the model, we simulated a series of simple and static nanoscale two-phase systems, including phase separation, a Laplace bubble, contact angle, and a static nanoconfined bubble. In this work, we demonstrate the use of our proposed LBM to model gas/water two-phase flow in systems like a single nanopore, two parallel nanopores, and nanoporous media. Our LBM simulations of static water-film and gas-film scenarios in nanopores agree well with the theory of disjoining pressure and serve as critical steps toward validating this approach. This work highlights the importance of interfacial forces in determining static and dynamic fluid behaviors at the nanoscale. In the Applications section, we determine the water-film thickness and disjoining pressure in a hydrophilic nanopore under the drainage process. Next, we model water imbibition into gas-filled parallel nanopores with different wettability, and simulate gas/water two-phase flow in dual-wettability nanoporous media. The results showed that isolated patches of organic matters (OMs) impede water flow, and the water relative permeability curve cuts off at water saturation [= 1–volumetric total organic carbon (TOC)]. The residual gas saturation is also controlled by the volumetric TOC, ascribed to the isolation of organic patches by the saturating water; therefore, the gas relative permeability curve cuts off at water saturation (= 1–volumetric TOC).

The Numerical Simulation Study of the Oil–Water Seepage Behavior Dependent on the Polymer Concentration in Polymer Flooding

It is well acknowledged that due to the polymer component, the oil–water relative permeability curve in polymer flooding is different from the curve in waterflooding. As the viscoelastic properties and the trapping number are presented for modifying the oil–water relative permeability curve, the integration of these two factors for the convenience of simulation processes has become a key issue. In this paper, an interpolation factor Ω that depends on the normalized polymer concentration is firstly proposed for simplification. Then, the numerical calculations in the self-developed simulator are performed to discuss the effects of the interpolation factor on the well performances and the applications in field history matching. The results indicate that compared with the results of the commercial simulator, the simulation with the interpolation factor Ω could more accurately describe the effect of the injected polymer solution in controlling water production, and more efficiently simplify the combination of factors on relative permeability curves in polymer flooding. Additionally, for polymer flooding history matching, the interpolation factor Ω is set as an adjustment parameter based on core flooding results to dynamically consider the change of the relative permeability curves, and has been successfully applied in the water cut matching of the two wells in Y oilfield. This investigation provides an efficient method to evaluate the seepage behavior variation of polymer flooding.