We investigate the dynamic adsorption of anionic surfactant C 14 − 16 alpha olefin sulfonate on Berea sandstone cores with different surface wettability and redox states under high temperature that represents reservoir conditions. Surfactant adsorption levels are determined by analyzing the effluent history data with a dynamic adsorption model assuming Langmuir isotherm. A variety of analyses, including surface chemistry, ionic composition, and chromatography, is performed. It is found that the surfactant breakthrough in the neutral-wet core is delayed more compared to that in the water-wet core because the deposited crude oil components on the rock surface increase the surfactant adsorption via hydrophobic interactions. As the surfactant adsorption is satisfied, the crude oil components are solubilized by surfactant micelles and some of the adsorbed surfactants are released from the rock surface. The released surfactant dissolves in the flowing surfactant solution, thereby resulting in an overshoot of the produced surfactant concentration with respect to the injection value. Furthermore, under water-wet conditions, changing the surface redox potential from an oxidized to a reduced state decreases the surfactant adsorption level by 40%. We find that the decrease in surfactant adsorption is caused not only by removing the iron oxide but also by changing the calcium concentration after the core restoration process (calcite dissolution and ion exchange as a result of using EDTA). Findings from this study suggest that laboratory surfactant adsorption tests need to be conducted by considering the wettability and redox state of the rock surface while recognizing how core restoration methods could significantly alter the ionic composition during surfactant flooding.
Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity. In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator's results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor. The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.
Summary A surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored. In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90°C with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility. During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process. Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.
Summary The application of surfactants in enhanced oil recovery (EOR) has revealed over the years various challenges that impose limitations on the successful implementation of surfactant flooding. Surfactant adsorption is one of the most important aspects that strongly dictates the feasibility of surfactant-based EOR. The effect of the presence of crude oil on surfactant adsorption and the influence of surfactant partitioning on the adsorption quantification are presented in this paper. Static adsorption experiments were conducted in this study for a surfactant mixture [alkyl ether carboxylate (AEC):alkylpolyglucoside (APG)] on sandstone rock samples in the absence and presence of crude oil. Partitioning experiments were carried out to evaluate the surfactant partitioning between the aqueous surfactant solution and the crude oil to determine the partitioning influence on the adsorption results in the presence of crude oil. The mixture’s adsorption and partitioning behaviors were studied at a fixed salinity of 32 k ppm and temperatures of 80 and 106°C. High-performance liquid chromatography (HPLC) was used in measuring the surfactant concentration throughout adsorption and partitioning tests. Rock characterization was also performed in this study using X-ray diffraction (XRD) as well as X-ray photoelectron spectroscopy (XPS) before and after adsorption with and without crude oil being present. Static adsorption outcomes displayed the adsorption of APG, AEC, and the overall mixture with and without crude oil being present, because all are having a similar increasing trend when concentration increases. However, the adsorption values were much higher when crude oil was present as compared with the adsorption values when crude oil was absent; this is because of not considering the impact of surfactant partitioning. The adsorption values (i.e., at 0.2 wt%) for both temperatures were below 2.5 mg/g in the absence of crude oil and rose to around 3.5 mg/g in the presence of crude oil. A significant amount of what was adsorbed belongs to AEC because of its increased chain-chain interactions with APG, which was evidenced experimentally in our previous work; hence, AEC is the greatest contributor to the overall surfactant mixture’s adsorption. Also, temperature had an impact on the adsorption capacity of the AEC:APG mixture, showing that APG has a greater sensitivity to temperature in comparison to AEC. The adsorption behavior of APG was found to be the opposite of AEC, where the adsorption capacity at 106°C was lower for AEC than its adsorption capacity at 80°C and vice versa for APG. The surfactant partitioning results were used to validate the surfactant adsorption outcomes in the presence of crude oil. After eliminating the partitioning effect, the surfactant adsorption isotherms in both cases of the presence and the absence of crude oil were almost identical. The results highlighted the importance of measuring surfactant partitioning, and the impact that partitioning has on the total surfactant losses during the surfactant flooding process. XRD and XPS results indicated that the change of the rock structure after adsorption when crude oil was present was attributed to the rock dissolution phenomena. It was concluded that adsorption and partitioning take place in the water/oil/rock system simultaneously and taking that into account allows for the improved and proper designing of the surfactant flooding.
Summary This paper advances the understanding of foam transport in heterogeneous porous media for enhanced oil recovery (EOR). Specifically, we investigate the dependence of methane foam rheology on the rock permeability at the laboratory scale and then extend the observations to the field scale with foam modeling techniques and reservoir simulation tools. The oil recovery efficiency of conventional gasflooding, waterflooding, and water-alternating-gas (WAG) processes can be limited by constraints such as bypassing effects (including both viscous fingering and channeling mechanisms) and gravity override. The problem can be more severe if the reservoir is highly fractured or heterogeneously layered in the direction of flow. Foam offers the promise to address the three issues simultaneously by better controlling the mobility of injected fluids. However, limited literature data of foam-flooding experiments were reported using actual reservoir cores at harsh conditions. In this paper, a series of methane (CH4) foam-flooding experiments were conducted in three different actual cores from a proprietary reservoir at an elevated temperature. It is found that foam rheology is significantly correlated with the rock permeability. To quantify the mobility control offered by foam, we calculated the apparent viscosity on the basis of the measured pressure drop at steady state. Interestingly, the apparent viscosity was found to be selectively higher in the high-permeability cores compared with that in the low-permeability zones. We parameterized our system using a texture-implicit-local-equilibrium model (STARS™ simulator, Computer Modelling Group, Calgary, Alberta, Canada) to illustrate the dependence of foam parameters on rock permeability. In addition, we created a two-layered model reservoir using an in-house simulator called modular reservoir simulator (MoReS; Shell Research, Rijswijk, The Netherlands) to elucidate the role of different driving forces for fluid diversion at the field level. We took into consideration the combined effect of gravitational, viscous force, and capillary forces in our simulation. We show that the gravitational forces prevent the gas from sweeping the lower part of the reservoir. However, the poor sweep can be ameliorated by intermittent surfactant injection to generate foam. In addition, the capillary force which hinders the gas (nonwetting phase) from entering the low-permeability region can be effectively leveraged to redistribute the fluids in the porous media, resulting in better sweep efficiency. We conclude that foam if properly designed can effectively improve the conformance of the WAG EOR in the presence of reservoir heterogeneity.
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