The growing demand for clean energy can be met by improving the recovery of current resources. One of the effective methods in recovering the unswept reserves is chemical flooding. Microemulsion flooding is an alternative for surfactant flooding in a chemical-enhanced oil recovery method and can entirely sweep the remaining oil in porous media. The efficiency of microemulsion flooding is guaranteed through phase behavior analysis and customization regarding the actual field conditions. Reviewing the literature, there is a lack of experience that compared the macroscopic and microscopic efficiency of microemulsion flooding, especially in low viscous oil reservoirs. In the current study, one-quarter five-spot glass micromodel was implemented for investigating the effect of different parameters on microemulsion efficiency, including surfactant types, injection rate, and micromodel pattern. Image analysis techniques were applied to represent the phase saturations throughout the microemulsion flooding tests. The results confirm the appropriate efficiency of microemulsion flooding in improving the ultimate recovery. LABS microemulsion has the highest efficiency, and the increment of the injection rate has an adverse effect on oil recovery. According to the pore structure’s tests, it seems that permeability has little impact on recovery. The results of this study can be used in enhanced oil recovery designs in low-viscosity oil fields. It shows the impact of crucial parameters in microemulsion flooding.

Fluid flow in gas condensate reservoirs usually exhibit complex flow behavior when the flowing bottomhole pressure drops below the dew-point. As a result, different flow regions with different characteristics are created within the reservoir. These flow regions can be identified by well test interpretation. The use of well test analysis for quantifying near well and reservoir behavior is well established for the case of simple single-layer homogenous systems. The behavior, however, is more complex in cases where different rock types or layering effects co-exist. In these cases, distinguishing between reservoir effects and fluid effects is challenging and needs a variety of analytical and numerical tools. The aim of this study is to investigate the liquid condensation effects on well test behavior of naturally fractured gas condensate through simulation approach in two different rock properties in a giant naturally fractured gas condensate field in south of Iran. A single well compositional model is developed to determine early-time, transition-time and late-time characteristics of the pressure transient data under condition of below dewpoint pressure. Then compositional model has been used to verify the results obtained from conventional well test analysis in this field. The results of this study would improve modeling of the surrounding area in mentioned field. Interpretation of compositional model outputs have shown that condensate deposit near the wellbore yields a well test composite behavior in early and late time similar to what is found in single porosity homogenous system, but superimposed on double-permeability behavior. The behavior, however, is more complex in transition time which cause delay in hydrocarbon flow from the matrix blocks towards the fractures and lead to decrease in interlayer cross flow coefficient.

Naturally fractured reservoirs (NFR) represent an important percentage of worldwide hydrocarbon reserves and production. The performance of naturally fractured gas condensate reservoirs would be more complicated regarding both rock and fluid effects. In contrast to the dual-porosity model, dual-porosity/dual-permeability (dual-permeability) model is considered as a modified model, in which flow to the wellbore occurs through both matrix and fracture systems. Fluid flow in gas condensate reservoirs usually demonstrates intricate flow behavior when the flowing bottom-hole pressure falls below the dew point. Accordingly, different regions with different characteristics are formed within the reservoir. These regions can be recognized by pressure transient analysis. Consequently, distinguishing between reservoir effects and fluid effects is challenging in these specific reservoirs and needs numerical simulation. The main objective of this paper is to examine the effect of condensate banking on the pressure behavior of lean and rich gas condensate NFRs through a simulation approach. Subsequently, evaluation of early-time characteristics of the pressure transient data is provided through a single well compositional simulation model. Then, drawdown, buildup, and multirate tests are conducted to establish the condition in which the flowing bottom-hole pressure drops below the dew point causing retrograde condensation. The simulation results are confirmed through well test analysis in both Iranian naturally fractured rich and lean gas condensate fields. Interpretations of simulation analysis revealed that the richer gas is more prone to condensation. When the pressure drops below the dew point, the pressure derivative curves in the rich gas system encounter a more shift to the right, and the trough becomes more pronounced as compared to the lean one.