Novel fabrication of mixed wettability micromodels for pore-scale studies of fluid-rock interactions.

Wettability plays a crucial role in multiphase fluid flow in porous media, impacting various geological applications such as hydrocarbon extraction, aquifer remediation, and carbon dioxide sequestration. Microfluidic methods have attracted interest for their capacity to explore and visualize essential multiphase flow dynamics at the pore level, mimicking actual rock pore structures. However, creating micromodels with representative mixed wettability is currently a challenge. Existing technology is limited to producing micromodels with a singular wettability, either water-wet or oil-wet, leaving a gap in representing mixed-wet scenarios. In this study, we introduce a novel method to fabricate microfluidic devices with controlled spatial distribution of wettability at the micro-scale, mimicking actual configurations of mixed-wet rocks arising from varied mineralogy and pore structures. The proposed method combines the soft lithography process with thin film deposition techniques. The micromodels were designed to mimic the pore network of actual reservoir rocks, and a silicon substrate served as the foundation for the photolithography process optimization and wettability alteration methodology. Perfluorodecyltrichlorosilane coating was applied using molecular vapor deposition technology for surface wettability modification. The coated parts of the microdevice substrate altered the localized wetting state of the silicon towards hydrophobic, while the wettability remained unchanged in the non-coated areas. We utilized surface measurements, including contact angle, X-ray photoelectron spectroscopy, transmission electron microscopy, scanning electron microscopy, and atomic force microscopy, to assess the wettability, composition, thickness, shape, roughness, and overall quality of the coating. Our fabrication process successfully produced a microfluidics device with tailored mixed-wet attributes at the micro-scale, which is, to our best knowledge, the first achievement in the field. This method enables the replication of mixed-wet characteristics commonly seen in various applications, such as carbonates and shales within underground rocks, providing a more accurate examination of fundamental multiphase fluid dynamics and rock interactions at the pore level.

Elastometry of Complex Fluid Pendant Capsules.

Oil/water interfaces are ubiquitous in nature. Opposing polarities at these interfaces attract surface-active molecules, which can seed complex viscoelastic or even solid interfacial structure. Biorelevant proteins such as hydrophobin, polymers such as PNIPAM, and the asphaltenes in crude oil (CRO) are examples of some systems where such layers can occur. When a pendant drop of CRO is aged in brine, it can form an interfacial elastic membrane of asphaltenes so stiff that it wrinkles and crumples upon retraction. Most of the work studying CRO/brine interfaces focuses on the viscoelastic liquid regime, leaving a wide range of fully solidified, elastic interfaces largely unexplored. In this work, we quantitatively measure elasticity in all phases of drop retraction. In early retraction, the interface shows a fluid viscoelasticity measurable using a Gibbs isotherm or dilatational rheology. Further retraction causes a phase transition to a 2D elastic solid with nonisotropic, nonhomogeneous surface stresses. In this regime, we use new techniques in the elastic membrane theory to fit for the elasticities of these solid capsules. These elastic measurements can help us develop a deeper understanding not only of CRO interfaces but also of the myriad fluid systems with solid interfacial layers.

Systematic observations of enhanced oil recovery and associated changes at carbonate-brine and carbonate-petroleum interfaces.

Enhanced oil recovery (EOR) from carbonates is obtained by injection of controlled ionic strength brines containing "active ions" (e.g., SO42-, Mg2+, Ca2+). It is generally believed that this occurs through the interaction of the active ions at the carbonate-brine interface (e.g., within a thin brine layer separating the petroleum and the carbonate phases). Here, in-situ observations show how one active ion, SO42-, alters behavior at the carbonate-petroleum interface. Displacement of petroleum from initially oil-wet carbonate rocks using brines with variable SO4 concentrations systematically changes oil recovery, in situ contact angles, and connectivity of the oil phase, confirming that the active ion alters interactions at the oil/brine/carbonate interface, as expected. Measurements of model calcite-fluid interfaces show that there is no measurable sorption of SO4 to carbonate-brine interfaces but reveals that the carbonate-petroleum interface is altered by previous exposure to SO4-containing brines. These results suggest that EOR in carbonates is controlled indirectly by active ions. We propose that this may be due to a reduced oleophilicity of the carbonate caused by chemical complexation between the active ion and petroleum's acidic and basic functional groups. This mechanism explains how both anions and cations act as active ions for EOR in carbonates.

Oil Displacement in Calcite-Coated Microfluidic Chips via Waterflooding at Elevated Temperatures and Long Times.

In microfluidic studies of improved oil recovery, mostly pore networks with uniform depth and surface chemistry are used. To better mimic the multiple porosity length scales and surface heterogeneity of carbonate reservoirs, we coated a 2.5D glass microchannel with calcite particles. After aging with formation water and crude oil (CRO), high-salinity Water (HSW) was flooded at varying temperatures and durations. Time-resolved microscopy revealed the CRO displacements. Precise quantification of residual oil presented some challenges due to calcite-induced optical heterogeneity and brine-oil coexistence at (sub)micron length scales. Both issues were addressed using pixel-wise intensity calibration. During waterflooding, most of the ultimately produced oil gets liberated within the first pore volume (similar to glass micromodels). Increasing temperature from 22 °C to 60 °C and 90 °C produced some more oil. Waterflooding initiated directly at 90 °C produced significantly more oil than at 22 °C. Continuing HSW exposure at 90 °C for 8 days does not release additional oil; although, a spectacular growth of aqueous droplets is observed. The effect of calcite particles on CRO retention is weak on flat surfaces, where the coverage is ~20%. The calcite-rich pore edges retain significantly more oil suggesting that, in our micromodel wall roughness is a stronger determinant for oil retention than surface chemistry.

Functionalized Nanomembranes and Plasma Technologies for Produced Water Treatment: A Review.

The treatment of produced water, associated with oil & gas production, is envisioned to gain more significant attention in the coming years due to increasing energy demand and growing interests to promote sustainable developments. This review presents innovative practical solutions for oil/water separation, desalination, and purification of polluted water sources using a combination of porous membranes and plasma treatment technologies. Both these technologies can be used to treat produced water separately, but their combination results in a significant synergistic impact. The membranes functionalized by plasma show a remarkable increase in their efficiency characterized by enhanced oil rejection capability and reusability, while plasma treatment of water combined with membranes and/or adsorbents could be used to soften water and achieve high purity.

Absence of anomalous underscreening in highly concentrated aqueous electrolytes confined between smooth silica surfaces.

Recent surface forces apparatus experiments that measured the forces between two mica surfaces and a series of subsequent theoretical studies suggest the occurrence of universal underscreening in highly concentrated electrolyte solutions. We performed a set of systematic Atomic Force Spectroscopy measurements for aqueous salt solutions in a concentration range from 1 mM to 5 M using chloride salts of various alkali metals as well as mixed concentrated salt solutions (involving both mono- and divalent cations and anions), that mimic concentrated brines typically encountered in geological formations. Experiments were carried out using flat substrates and submicrometer-sized colloidal probes made of smooth oxidized silicon immersed in salt solutions at pH values of 6 and 9 and temperatures of 25 °C and 45 °C. While strong repulsive forces were observed for the smallest tip-sample separations, none of the conditions explored displayed any indication of anomalous long range electrostatic forces as reported for mica surfaces. Instead, forces are universally dominated by attractive van der Waals interactions at tip-sample separations of ≈2 nm and beyond for salt concentrations of 1 M and higher. Complementary calculations based on classical density functional theory for the primitive model support these experimental observations and display a consistent decrease in screening length with increasing ion concentration.

Molecular-scale origins of wettability at petroleum-brine-carbonate interfaces.

Wettability control of carbonates is a central concept for enhanced petroleum recovery, but a mechanistic understanding of the associated molecular-scale chemical processes remains unclear. We directly probe the interface of calcium carbonate (calcite) with natural petroleum oil, synthetic petroleum analogues, and aqueous brines to understand the molecular scale behavior at this interface. The calcite-petroleum interface structure is similar whether or not calcite was previously exposed to an aqueous brine, and is characterized by an adsorbed interfacial layer, significant structural changes within the calcite surface, and increased surface roughness. No evidence for an often-assumed thin-brine wetting layer at the calcite-petroleum interface is observed. These features differ from those observed at the calcite-brine interface, and for parallel measurements using model synthetic petroleum mixtures (consisting of representative components, including dodecane, toluene, and asphaltene). Changes to the interface after petroleum displacement by aqueous brines are also discussed.

Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery.

Over the past few decades, field- and laboratory-scale studies have shown enhancements in oil recovery when reservoirs, which contain high-salinity formation water (FW), are waterflooded with modified-salinity salt water (widely referred to as the low-salinity, dilution, or SmartWater effect for improved oil recovery). In this study, we investigated the time dependence of the physicochemical processes that occur during diluted seawater (i.e., SmartWater) waterflooding processes of specific relevance to carbonate oil reservoirs. We measured the changes to oil/water/rock wettability, surface roughness, and surface chemical composition during SmartWater flooding using 10-fold-diluted seawater under mimicked oil reservoir conditions with calcite and carbonate reservoir rocks. Distinct effects due to SmartWater flooding were observed and found to occur on two different timescales: (1) a rapid (<15 min) increase in the colloidal electrostatic double-layer repulsion between the rock and oil across the SmartWater, leading to a decreased oil/water/rock adhesion energy and thus increased water wetness and (2) slower (>12 h to complete) physicochemical changes of the calcite and carbonate reservoir rock surfaces, including surface roughening via the dissolution of rock and the reprecipitation of dissolved carbonate species after exchanging key ions (Ca2+, Mg2+, CO32-, and SO42- in carbonates) with those in the flooding SmartWater. Our experiments using crude oil from a carbonate reservoir reveal that these reservoir rock surfaces are covered with organic-ionic preadsorbed films (ad-layers), which the SmartWater removes (detaches) as flakes. Removal of the organic-ionic ad-layers by SmartWater flooding enhances oil release from the surfaces, which was found to be critical to increasing the water wetness and significantly improving oil removal from carbonates. Additionally, the increase in water wetness is further enhanced by roughening of the rock surfaces, which decreases the effective contact (interaction) area between the oil and rock interfaces. Furthermore, we found that the rate of these slower physicochemical changes to the carbonate rock surfaces increases with increasing temperature (at least up to an experimental temperature of 75 °C). Our results suggest that the effectiveness of improved oil recovery from SmartWater flooding depends strongly on the formation of the organic-ionic ad-layers. In oil reservoirs where the ad-layer is fully developed and robust, injecting SmartWater would lead to significant removal of the ad-layer and improved oil recovery.

A new mechanistic Parachor model to predict dynamic interfacial tension and miscibility in multicomponent hydrocarbon systems.

Widely used traditional Parachor model fails to provide reliable interfacial tension predictions in multicomponent hydrocarbon systems due to the inability of this model to account for mass transfer effects between the fluid phases. In this paper, we therefore proposed a new mass transfer enhanced mechanistic Parachor model to predict interfacial tension and to identify the governing mass transfer mechanism responsible for attaining the thermodynamic fluid phase equilibria in multicomponent hydrocarbon systems. The proposed model has been evaluated against experimental data for two gas-oil systems of Rainbow Keg River and Terra Nova reservoirs. The results from the proposed model indicated good IFT predictions and that the vaporization of light hydrocarbon components from crude oil to gas phase is the governing mass transfer mechanism for the attainment of fluid phase equilibria in both the gas-oil systems used. A multiple linear regression model has also been developed for a priori prediction of exponent in the mechanistic model by using only the reservoir fluid compositions, without the need for experimental measurements. The dynamic nature of interfacial tensions observed in the experiments justifies the use of diffusivities in the mechanistic model, thus enabling the proposed model predictions to determine dynamic gas-oil miscibility conditions in multicomponent hydrocarbon systems.