The benefits and advantages of waterflood are well-known with many decades of application in a wide range of reservoirs with different crude oil and rock types. However, the average global recover factor for waterflood is only around 30%. There is, therefore, great interest in developing methods that can augment waterflood and improve its recovery factor from the current low values. It has been shown that enriching water with CO2 and injecting it in the form of carbonated water can improve the performance of water flood significantly 1-15. However, a complete understanding of the pore-scale interactions and events taking place during carbonated water injection (CWI) in an oil reservoir and the actual mechanisms by which additional oil may be recovered are still missing and therefore the true potential of CWI is not yet well known. This is further complicated by the fact that the current commercial reservoir simulators are not able to adequately simulate the complex and multi-physics processes that take place during CWI which include both fluid/fluid and rock/fluid interactions. The objective of the Carbonated Water Injection (CWI) JIP at Heriot-Watt University is to perform a thorough investigation of the performance of CWI under reservoir conditions and systematically study the parameters that impact the amount of oil recovery by CWI and its underlying mechanisms. Here we present the results of a series of CWI experiments performed under reservoir conditions at pore-scale and core-scale. Direct flow visualisation results of our high-pressure micromodel experiments reveal very vividly the pore-scale events that take place as CO2 gradually leaves the injected carbonated water and dissolves in the oil. The results show that the pore-scale interactions of carbonated water with crude oil are quite different from the well-known mechanisms observed in conventional CO2 flood. Apart from the usual CO2-related mechanisms such as oil swelling and viscosity reduction, in CWI, formation of a new fluid phase within the oil is observed. As we will show, this is a major mechanism that significantly improves the performance of CWI and the amount of additional oil recovery achieved by CWI. Our coreflood experiments confirm our pore-scale flow visualization results and clearly show that, compared to conventional waterflood, CWI can lead to substantial additional oil recovery under both secondary mode (injected instead of conventional water flood) and tertiary mode (injected after conventional water flood). The performance of CWI is significantly affected by the composition of the oil including the amount of light and intermediate hydrocarbons dissolved (solution gas) in crude oil.

Summary The underlying mechanism of oil recovery by low-salinity-water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature, but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct-flow-visualization investigations (Emadi and Sohrabi 2013) have revealed that a physical phenomenon takes place when certain crude oils are contacted by low-salinity water, leading to a spontaneous formation of micelles that can be seen in the form of microdispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude-oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include direct-flow (micromodel) visualization, crude-oil characterization, coreflooding, and spontaneous-imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface-active components of crude oil, and the improvement in oil recovery because of LSWI. We present the results of a series of spontaneous- and forced-imbibition experiments carefully designed with reservoir cores to investigate the role of the microdispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing an LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared with high-salinity-water injection (HSWI) in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude-oil/brine-interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicate that the natural surface-active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research can be applied to oil recovery from both sandstone and carbonate oil reservoirs because they are mainly derived from fluid/fluid interactions that control wettability alteration in both sandstone and carbonate rocks.

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Foam has been used for controlling gas mobility during injection processes in order to mitigate the adverse effects of low gas viscosity, reservoir heterogeneity and gravity override. In addition, foam has also been employed in near-wellbore production, matrix acidizing stimulation, hydraulic fracturing, gas shut-off and water shut-off. The optimization of these operations requires a good understanding of the physical characteristics of foam and its behavior under reservoir conditions. Despite numerous experimental and theoretical studies on foam and some field applications reported in the literature, there is no comprehensive literature survey detailing the knowledge and experience gained through the application of foam. The aim of this paper is to present a critical review of the literature available on the use of foam injection for enhanced oil recovery. An extensive appraisal of the current status of foam application in EOR methods is a useful way of presenting advantages, shortcomings and limitations of the process as well as supplementary advances. Special attention has been given to the review of new research topics, such as the use of foam as a mobility control agent. Advances in more efficient foaming agents, additives and boosters are discussed. Moreover, in depth analysis of field applications of foam in EOR projects show that the main problems encountered during field-scale foam applications are related to foam stability, foam compatibility, as well as adsorption of the injected chemicals onto the rock surface. To address this, we discuss the evolution of the pilot field application and the reasons for inconsistency between laboratory results and field scale performance.

The underlying mechanism of oil recovery by low salinity water injection (LSWI) is still unknown. It would, therefore, be difficult to predict the performance of reservoirs under LSWI. A number of mechanisms have been proposed in the literature but these are controversial and have largely ignored crucial fluid/fluid interactions. Our direct flow visualization investigations have revealed that a physical phenomenon takes place when certain crude oils are contacted by low salinity water leading to a spontaneous formation of micelles which can be seen in the form of micro-dispersions in the oil phase. In this paper, we present the results of a comprehensive study that includes experiments at different scales designed to systematically investigate the role of the observed crude oil/brine interaction and micelle formation in the process of oil recovery by LSWI. The experiments include; direct flow (micromodel) visualization, crude oil characterization, coreflooding, and spontaneous imbibition experiments. We establish a clear link between the formation of these micelles, the natural surface active components of crude oil, and the improvement in oil recovery due to LSWI. We present the results of a series of spontaneous and forced imbibition experiments carefully designed using reservoir cores to investigate the role of the micro-dispersions in wettability alteration and oil recovery. To further assess the significance of this mechanism, in a separate exercise, we eliminate the effect of clay by performing a LSWI experiment in a clay-free core. Absence of clay minerals is expected to significantly reduce the influence of the previously proposed mechanisms for oil recovery by LSWI. Nevertheless, we observe significant additional oil recovery compared to high salinity water injection in the clay-free porous medium. The additional oil recovery is attributed to the formation of micelles stemming from the crude oil/brine interaction mechanism described in this work and our previous related publications. Compositional analyses of the oil produced during this coreflood experiment indicates that the natural surface active compounds of the crude oil had been desorbed from the rock surfaces during the LSWI period of the experiment when the additional oil was produced. The results of this study present new insights into the fundamental mechanisms involved in oil recovery by LSWI and new criteria for evaluating the potential of LSWI for application in oil reservoirs. The fluid/fluid interactions revealed in this research applies to oil recovery from both sandstone and carbonate oil reservoirs.

No abstract

The salt content and composition of the water that is either produced with the oil or injected in an oil reservoir can change the composition of the oil at the oil/water interface. Having identified these compositional changes is key to designing the most optimized water ionic recipe to be used in waterflooding of an oil reservoir. Hence, there is a need to better understand the physicochemical interactions at the oil/water interface because of salinity effects. This study elucidates the effect of salinity on the interfacial interactions through pendant drop measurements of crude oil/water interfacial tension, surface charge evaluation by zeta potential, water content measurements by Karl Fischer titration, Fourier transform infrared (FT-IR), and ultraviolet–visible spectroscopy analyses. The interfacial tension results indicate that the interfacial tension increases with reduction in water salinity, which is shown for the first time by FT-IR and water content measurements to be proportional to the spontaneous formation of water microdispersion as the main mechanism of low salinity water injection. Formation of microdispersions and partitioning of surface-active materials by conjugated acidic compounds and/or acidic asphaltenes and low-molecular weight acidic compounds, respectively, are the main parameters controlling the crude oil/water interactions. Asphaltenes and acidic materials are shown to be the underlying compounds in the crude oil phase promoting the microdispersion formation.

This study concerns with the microscopic and macroscopic fluid distribution and flow behavior during water alternating solvent (WAS) injection process to heavy oil using micromodel generated from thin section of a real rock which has rarely attended in the available literature. In this study, a one-quarter five-spot glass micromodel was deployed to examine the effect of flow media topology on microscopic displacements as well as macroscopic efficiency of WAS process. The micromodel was initially saturated with the heavy oil, and then the hydrocarbon solvent and water were injected alternately into it. The observations confirmed that WAS injection scheme is an effective method for the recovery of the significant amount of residual oil. Using solvent as the leading batch in WAS scheme can really improve the oil recovery by increasing the amount of microscopic sweep efficiency in flow paths, where the molecular diffusion in solvent-heavy oil system occurs. Presence of connate water in WAS scheme can improve the recovery efficiency especially at higher water saturations. Heterogeneity of the medium caused the water to be distributed better in the medium, but the amount of residual oil in the flow area is going to be increased. Small precipitates of asphaltene particles due to solvent injection and localized entrapment of the oil due to heterogeneity effects, water blockage, and deadend pores were observed mainly in this process. The results of this study reveals the pore scale events in WAS injection process and will be helpful for developing reliable simulation models.