Foam can increase sweep efficiency within a porous medium, which is useful for oil-recovery processes [1]. The flow of foam in porous media is a complex process that depends on properties like permeability, porosity and surface chemistry, but also temperature. Although the surface activity of surfactants as a function of temperature is well described at the liquid/liquid or liquid/ gas interface, data on the effect of temperature on foam stability is limited, especially in porous media.In this work, we tested a surfactant (AOS) at different temperatures, from 20°C to 80°C, in a sandstone porous medium with co-injection of foam. The pressure gradient, or equivalently the apparent viscosity, was measured in steady-state experiments. The core-flood experiments showed that the apparent viscosity of the foam decreased by 50% when the temperature increased to 80°C. This effect correlates with the lower surface tension at higher temperatures. These results are compared to bulk foam experiments, which show that at elevated temperatures foam decays and coalesces faster. This effect, however, can be attributed to the faster drainage at high temperature, as a response to the reduction in liquid viscosity, and greater film permeability leading to faster coarsening. Our results using the STARS foam model show that one cannot fit foam-model parameters to data at one temperature and apply the model at other temperatures, even if one accounts for the change in fluid properties (surface tension and liquid viscosity) with temperature. Experiments show an increase in gas mobility in the low-quality foam regime with increasing temperature that is inversely proportional to the decrease in gas-water surface tension. In the high-quality regime, results suggest that the water saturation at which foam collapses fmdry increases and P c * decreases with increasing temperature.

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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.

One of the major challenges in the upstream oil and gas industry is to control and reduce high water production from a large number of oil wells. A relative permeability modifier (RPM) has been proven to offer a potential solution for excessive water production at core and field scales. A good RPM must be of a cost-effective and simple agent that could easily be prepared in the field to control water production without requiring major workover equipment. This paper discusses the performance of a newly formulated grafted nanoclay (GN) for conformance control at high-temperature conditions and application as a permeability modifier. The interfacial tension (IFT) reduction and wettability change were quantified via pendant drop and contact angle measurements, respectively. Laboratory studies were performed using Berea and native sandstone cores to determine the effect GN on effective water and oil permeability. Experimental results obtained revealed that upon injection GN can immediately create a high flow resistance to the injected water. The regained water and oil permeability were 16% and 89%, respectively, after GN injection when the Berea core was used. A similar high resistance factor to water was obtained when a native core was used. Adsorption of GN on the substrate reduced the contact angle toward water-wetting combined with a reduction in IFT from 20.78 ± 1.48 mN/m between an oil–brine system to 8.67 ± 1.01 mN/m for an oil–GN system. These new results highlighted new insights for successful applications of GN to improve reservoir conformance in oil production wells.

Reservoir heterogeneity and permeability contrast are some of the factors that affect the efficiency of EOR applications in the field. The main issues of current secondary and tertiary recovery methods such as water, gas, or water-alternating-gas (WAG) injections in the field are poor mobility control, gravity segregation, and viscous fingering, among others. Displacement conformance needs to be improved as to ensure that target regions are properly swept. To address these issues, foam has been proposed to complement the existing EOR applications, with the target to improve overall sweep efficiency through the reduction of gas mobility. However, very limited data of this effect are available on the actual reservoir rocks under field conditions. In this paper, laboratory research work was conducted to capture the effect of heterogeneity on foam using actual reservoir rocks of varied permeabilities. It is observed that foam is more stable in high permeability cores compared to low permeability cores. Our finding in actual reservoir rocks is consistent with the literature observations conducted in outcrop core samples. Moreover, we used a texture-implicit-local-equilibrium model to parameterize our foam system. Mobility reduction of the gas phase by foam was found to be selectively higher in cores of higher permeabilities. Another finding from the model is that, in all cases, the parameter epcap, which regulates the significance of shear-dependent rheological behavior, approximately equals to 1. Foam exhibit Bingham-like fluid properties where pressure gradient is irrelevant to the shear rates. We also simulated our foam system in a hypothetical two-layered model reservoir using MoReS. We systematically compared the oil displacement by water-alternating-gas (WAG, no foam) process and by surfactant-alternating-gas (foam) process. It is concluded that foam can effectively improve the conformance of the oil displacement in presence of reservoir heterogeneity. The permeability-dependent foam rheology can divert the displacing fluids from the high-permeability region to the low-permeability region and therefore enhancing the overall oil recovery efficiency.