Enhanced oil recovery by smart waterflooding represents an implementable and attractive emerging oil recovery technology. For sandstone reservoirs, smart waterflooding has shown an outright incremental oil recovery in most laboratory and field tests while some promising experimental data have been presented from carbonates. It seems more difficult to assume a favorable performance for some reservoir formation a priori while dismissing the other, so more data and better understanding of the underlying mechanism in carbonates are needed. This paper describes a series of experiments on Middle East carbonate core plugs designed to determine the impact of formation water and different versions of seawater (which has its sulfate concentration increased in the ratio (0.5:1:2:4:8) on oil recovery, wettability and surface charge modification. The results obtained lead to the following conclusions: Coreflooding experiments at 2300F and 3000psi with formation brine and various versions of seawater coupled with spiking sulfate concentration executed on carbonate core aged showed an incremental recovery of about 10% OOIC; An increasing concentration of sulfate in the seawater makes a Crude Oil/Brine/Rock system less oil-wet; The higher the sulfate concentration, the greater the repulsive forces in the electrical double layer, thereby forming an aggregate and detaching the oil from the rock surface, while increasing the sulfate concentration beyond four times seems ineffective as it gave a swift increase in pH and rock surface charges; The results obtained are therefore discussed within the framework of mechanisms previously described for smart water's ability to enhance oil recovery. The study concluded that a relatively economical modification of injection brine composition could considerably increase oil recovery.

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Brine-dependent recovery, which involves injected water ionic composition and strength, has seen much global research efforts in the past two decades because of its benefits over other oil recovery methods. Several studies, ranging from lab coreflood experiments to field trials, indicate the potential of recovering additional oil in sandstone and carbonate reservoirs. Sandstone and carbonate rocks are composed of completely different minerals, with varying degree of complexity and heterogeneity, but wettability alteration has been widely considered as the consequence rather than the cause of brine-dependent recovery. However, the probable cause appears to be as a result of the combination of several proposed mechanisms that relate the wettability changes to the improved recovery. This paper provides a comprehensive review on laboratory and field observations, descriptions of underlying mechanisms and their validity, the complexity of the oil-brine-rock interactions, modeling works, and comparison between sandstone and carbonate rocks. The improvement in oil recovery varies depending on brine content (connate and injected), rock mineralogy, oil type and structure, and temperature. The brine ionic strength and composition modification are the two major frontlines that have been well-exploited, while further areas of investigation are highlighted to speed up the interpretation and prediction of the process efficiency.

It has been amply proven through laboratory studies, affirmed by a few field trials, that dilution of brine injected has a potent impact on improving oil recovery in carbonate reservoirs. However, debate still exists as to the mechanisms responsible for such impact. The widely acknowledged underlying mechanism is the wettability alteration, achieved through a combination of lower ionic strength, multi-ion exchange, surface charge and mineral alteration. Therefore, the motive behind this study is to develop a model that can further support and interpret the brine dilution approach in the framework of carbonate reservoirs. In this paper, we formulated a theory for the observed behavior that coupled equations of multi-component transport and geochemical reactions. The geochemical system considered a choice of significant ions and minerals, relevant to the published experiments. Mechanisms included in the model were dispersion/diffusion, instantaneous equilibrium reactions in terms of intra-aqueous and sorption reactions, and non-equilibrium rate controlled kinetic reactions-mineral alteration. The equivalent modification in wettability was represented by interpolating through a set of flow functions, particularly the relative permeability characteristics. The model was employed to interpret recently published experimental data on carbonate core plugs (Austad et al. (2011); Yousef et al. (2011); Yi and Sarma (2012); Chandrasekhar and Mohanty (2013)) where systematic dilutions of injectate against the initial formation brine were analyzed. Considering known values of injection rate, thermodynamic equilibrium constants, and reaction rate constants, the model was able to capture the trend of the experimental oil recovery and effluent ion concentrations. Thus, the model could help interpret the observed behavior as a sequel to an interplay between surface charge and mineral alteration. The trend typically reflected a speedy transient period at early times, trailed by relaxed transient period and finally reaching a steady state solution. The model was used to closely examine the dominant chemical mechanism responsible for improved oil mobilization relating to brine dilution during smart waterflooding. A thorough understanding of the mechanisms at play during any recovery process is crucial for its successful implementation as well as reliable production modeling, forecasting and optimization.

The world adds about 51 Gt of greenhouse gases to the atmosphere each year, which will yield dire global consequences without aggressive action in the form of carbon dioxide removal (CDR) and other technologies. A suggested guideline requires that proposed CDR technologies be capable of removing at least 1% of current annual emissions, about half a gigaton, from the atmosphere each year once fully implemented for them to be worthy of pursuit. Basalt carbonation coupled to direct air capture (DAC) can exceed this baseline, but it is likely that implementation at the gigaton-per-year scale will require increasing per-well CO2 injection rates to a point where CO2 forms a persistent, free-phase CO2 plume in the basaltic subsurface. Here, we use a series of thermodynamic calculations and basalt dissolution simulations to show that the development of a persistent plume will reduce carbonation efficiency (i.e., the amount of CO2 mineralized per kilogram of basalt dissolved) relative to existing field projects and experimental studies. We show that variations in carbonation efficiency are directly related to carbonate mineral solubility, which is a function of solution alkalinity and pH/CO2 fugacity. The simulations demonstrate the sensitivity of carbonation efficiency to solution alkalinity and caution against directly extrapolating carbonation efficiencies inferred from laboratory studies and small-injection-rate field studies conducted under elevated alkalinity and/or pH conditions to gigaton-per-year scale basalt carbonation. Nevertheless, all simulations demonstrate significant carbonate mineralization and thus imply that significant mineral carbonation can be expected even at the gigaton-per-year scale if basalts are given time to react.

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Extensive experimental studies during the last two decades have demonstrated improved oil recoveries through the injection of diluted brine in both sandstone and carbonate rocks. However, the mechanisms that lead to improved oil recovery in carbonate rocks are not well established, though wettability alteration has been widely cited as a primary mechanism. It is also important to understand the role of carbonate mineralogical composition during diluted brine injection on the geochemical interactions taken place. In this study, we have formulated a theory for the anticipated chemical interactions between oil, brine, and rock, and linked the geochemical interactions to multicomponent transport within the porous rock. In so doing, we investigated different hypotheses on the viable link between geochemical interactions and wettability modifications. Our simulation results could capture the trend in the experimental oil recovery and pressure differential results, together with the effluent ions and pH under varying mineralogical content. On the basis of our model, we infer that mineral alteration alone could not describe the observed behavior and that one has also to consider the interplay between surface charge and mineral alteration. We then followed with simulation of a quarter of a five-spot pattern to demonstrate that incremental recovery varied with different rock mineralogy. The outcomes of our study clearly highlight the need to establish the relationship between appropriate process mechanism(s) and impact of mineralogical content when implementing brine dilution-dependent oil recovery in carbonate reservoirs.