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.

Direct Imaging of Tunable Crystal Surface Structures of MOF MIL-101 Using High-Resolution Electron Microscopy.

Metal-organic frameworks (MOFs) are often synthesized using various additives to modulate the crystallization. Here, we report the direct imaging of the crystal surface of MOF MIL-101 synthesized with different additives, using low-dose high-resolution transmission electron microscopy (HRTEM), and identify three distinct surface structures, at subunit cell resolution. We find that the mesoporous cages at the outermost surface of MIL-101 can be opened up by vacuum heating treatment at different temperatures, depending on the MIL-101 samples. We monitor the structural evolution of MIL-101 upon vacuum heating, using in situ X-ray diffraction, and find the results to be in good agreement with HRTEM observations, which leads us to speculate that additives have an influence not only on the surface structure but also on the stability of framework. In addition, we observe solid-solid phase transformation from MIL-101 to MIL-53 taking place in the sample synthesized with hydrofluoric acid.

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.