Response of Non-Polar Oil Component on Low Salinity Effect in Carbonate Reservoirs: Adhesion Force Measurement Using Atomic Force Microscopy (original) (raw)

Influence of Surface Roughness on the Contact Angle due to Calcite Dissolution in an Oil–Brine–Calcite System: A Nanoscale Analysis Using Atomic Force Microscopy and Geochemical Modeling

Energy & Fuels, 2019

Low salinity water flooding appears to be a promising means to improve oil recovery in carbonate reservoirs due to a wettability alteration process. Contact angle measurement is a direct approach to reveal the wettability alteration in oil-brine-carbonate system. However, questions have been raised about using contact angle measurement to justify the wettability alteration. This is because contact angle may be significantly affected by surface roughness variation in the presence of low salinity water due to calcite dissolution during the contact angle measurement. To clarify the cause and effect of wettability alteration during low salinity water flooding, we measured contact angle on two calcite substrates with similar surface roughness

The effect of ionic strength on oil adhesion in sandstone - the search for the low salinity mechanism

Scientific reports, 2015

Core flood and field tests have demonstrated that decreasing injection water salinity increases oil recovery from sandstone reservoirs. However, the microscopic mechanism behind the effect is still under debate. One hypothesis is that as salinity decreases, expansion of the electrical double layer decreases attraction between organic molecules and pore surfaces. We have developed a method that uses atomic force microscopy (AFM) in chemical force mapping (CFM) mode to explore the relationship between wettability and salinity. We functionalised AFM tips with alkanes and used them to represent tiny nonpolar oil droplets. In repeated measurements, we brought our "oil" close to the surface of sand grains taken from core plugs and we measured the adhesion between the tip and sample. Adhesion was constant in high salinity solutions but below a threshold of 5,000 to 8,000 ppm, adhesion decreased as salinity decreased, rendering the surface less oil wet. The effect was consistent, ...

Impact of surface roughness on wettability of oil-brine-calcite system at sub-pore scale

Journal of Molecular Liquids, 2019

Wettability alternation appears to be an important physicochemical process in carbonate reservoirs during low salinity water flooding. Contact angle measurement is widely used as a simple and direct method to demonstrate wettability alteration by low salinity water. The effect of various parameters, e.g., brine salinity, oil composition, and rock mineralogy on contact angle have been well documented. However, uncertainty over effect of rock surface roughness on contact angle of oil-brine-calcite is a major impediment to upscaling laboratory results and predicting wettability at field scale, knowing oil-brine-rock interaction is governed by electrostatic forces. We thus measured contact angle of oil on calcite substrates with different surface roughness (17 nm, 366 nm, and 943 nm), in high and low salinity brines. Moreover, we compared our experimental results with contact angles predicted by Wenzel's equation. Contact angle results show that in high salinity brine, contact angles decreased from 170°to 134°(36°decrease) with increasing surface roughness from 17 to 943 nm, suggesting a less hydrophobic system. Similar correlation between contact angles and surface roughness was observed in low salinity brine. Nevertheless, contact angles only slightly decreased from 117°to 101°(16°decrease) in low salinity brine, suggesting the effect of surface roughness on contact angle is more subtle in low salinity condition. We also found that for oil-brine-calcite system, the correlation between contact angle and surface roughness contradicts the trend predicted by Wenzel's equation. This is largely because the surface forces that govern oil-brine-calcite interactions are not captured by Wenzel's equation. Therefore, we hypothesize that at pore-scale level, wettability alteration by low salinity brine will likely be more subtle than that shown by contact angles when performed on smooth substrates (at sub-pore scale). To predict contact angle at pore-scale, surface roughness and surface forces governing oilbrine-calcite interactions need to be considered. The findings of this research will provide further insight into water-assisted EOR in carbonate reservoirs.

Crude Oil/Brine/Rock Interactions during SmartWater Flooding in Carbonates: Novel Surface Forces Apparatus Measurements at Reservoir Conditions

SPE Improved Oil Recovery Conference, 2020

In our previous paper (SPE-190281-MS), we presented results from a suite of multiscale experiments to understand interactions occurring across crude oil/brine/carbonate rock interfaces with different brine compositions. A new atomic to molecular scale mechanism was proposed based on changes in adhesion energies at different length- and time-scales to explain SmartWater effects for improved oil recovery (IOR) in carbonates. It was also understood that SmartWater effect is due to three distinct but interrelated physico-chemical mechanisms, involving changes to the colloidal interaction forces, surface roughening due to dissolution and re-precipitation, and removal of pre-adsorbed organic-ionic ad-layers (termed ‘flakes’) from the rock surface.In the present study, we carried out surface forces apparatus (SFA) experiments to understand SmartWater IOR mechanisms at elevated temperatures and pressures (up to 150°C and 2,200 psi) representative of realistic reservoir conditions. The resul...

Low salinity water flooding in high acidic oil reservoirs: Impact of pH on wettability of carbonate reservoirs

Journal of Molecular Liquids, 2019

Wettability alteration has been identified as an important mechanism during low salinity water flooding in carbonate reservoirs. Oil composition, in particular, acidic and basic functional groups, plays an important role in regulating wettability. In this paper, we explored the potential of low salinity effect in reservoirs with high acidic components (acid number = 4.0 mg KOH/g and base number = 1.3 mg KOH/g) with a combination of approaches (e.g., contact angle and zeta potential measurements, and surface complexation modeling). We measured the contact angles of oil on calcite surfaces in presence of aqueous ionic solutions at different pH (3 and 8), salinity (0.01 and 1 mol/L), ion type (CaCl 2 and Na 2 SO 4) and temperatures (25-100 o C). Our results show that both salinity and ion type significantly affect contact angle at pH=8. However, at low pH (pH 3), the oil-brine-calcite system becomes strongly water-wet with minor effect from salinity, ion type, and temperature. Lowing salinity drives the zeta potential of both

Wetting of Mineral Surfaces by Fatty-Acid-Laden Oil and Brine: Carbonate Effect at Elevated Temperature

Energy & Fuels, 2019

Oil recovery yields from sandstone reservoirs strongly depend on the wetting properties of the rock. Carboxylic acids present in crude oil may decrease the water wettability by adsorbing onto the mineral surface via cation interactions. A highly simplified version of this scenario has been mimicked in the lab to study these mechanisms in more detail. In previous studies on oil/brine/mineral systems the formation of fatty acid monolayers on mica was observed, yielding water contact angles in ambient oil of up to 60°. Here we demonstrate that the presence of 2 mM bicarbonate (typical for brines) has a strong influence at temperatures above 40°C (as in reservoirs), yielding water contact angles in ambient oil up to 160°. Similar behavior was found for a variety of carboxylic acids. On increasing the (even) carbon number of simple fatty acids from 8 to 20, the contact angle becomes larger until it saturates at 16 carbon atoms. Similar hydrophobic layers are formed by pulling a sheet of mica through an oil/water interface at comparable velocities. By studying the nanometer-scale topography and chemistry of these dip-coated samples, we can infer that the adsorbed layer is composed of alternating carboxylic acid bilayers that are held together by a very thin intermediate layer containing calcium and (bi)carbonate ions. Exposure to low-salinity water makes the multilayers disappear and the mineral surface become water-wet again, demonstrating that the presence of these structures can lead to a strong salinity-dependent wettability alteration.

Mineral Interfaces and Oil Recovery: A Microscopic View on Surface Reconstruction, Organic Modification and Wettability Alteration of Carbonates

Energy & Fuels

While it is generally known that aging protocols have an important impact on the interaction between crude oil (CRO), brines, and mineral surfaces, the microscopic consequences of the various steps of aging have hardly been described. In this study, we characterize the properties of fluids and carbonate mineral surfaces throughout a series of equilibration steps at 95°C and correlate these microscopic observations with macroscopic contact angle measurements. Chemical equilibration of CRO (eqCRO) and FW (eqFW) leads to transfer of organic molecules from the former to the latter, causing also a pH change in the eqFW. Confocal Raman microscopy, atomic force microscopy, and infrared spectroscopy are used to reveal how consecutive aging of calcite in eqFW and eqCRO induces: first, in eqFW, considerable surface reconstruction and precipitation of mineral particles with colocalized organic species, and second, upon exposure to eqCRO, the formation of a second adlayer primarily composed of polyaromatic hydrocarbon-rich particles. Our results show how these interconnected microscopic chemical and topographical surface modifications give rise to more "oil wetting" contact angles after the two-step aging procedure.

Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs

Fuel, 2018

Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1-3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used SO 4 2-free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software. We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35°) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle = 175°) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([ > CaOH 2 + ][-COO − ] + [ > CO 3 − ][-NH + ] + [ > CO 3 − ][-COOCa + ]) increased with decreasing salinity. At pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.

Evaluating physicochemical properties of crude oil as indicators of low-salinity–induced wettability alteration in carbonate minerals

Scientific Reports, 2020

The injection of low-salinity brine enhances oil recovery by altering the mineral wettability in carbonate reservoirs. However, the reported effectiveness of low-salinity water varies significantly in the literature, and the underlying mechanism of wettability alteration is controversial. In this work, we investigate the relationships between characteristics of crude oils and the oils’ response to low-salinity water in a spontaneous imbibition test, aiming (1) to identify suitable indicators of the effectiveness of low-salinity water and (2) to evaluate possible mechanisms of low-salinity–induced wettability alteration, including rock/oil charge repulsion and microdispersion formation. Seven oils are tested by spontaneous imbibition and fully characterized in terms of their acidity, zeta potential, interfacial tension, microdispersion propensity, water-soluble organics content and saturate-aromatic-resin-asphaltene fractionation. For the first time, the effectiveness of low-salinity...

Effect of Rock Mineralogy and Oil Composition on Wettability Alteration and Interfacial Tension by Brine and Carbonated Water

Energy & Fuels, 2019

Wettability has a significant impact on flow of oil during enhanced oil recovery (EOR) and profound effect on fluids 14 distribution in oil fields. Mechanisms that influence the interaction between the injected water and the components of 15 crude oil in the presence of carbonate rock sample were investigated. The main objectives of this study were to investigate 16 the role of both rock mineralogy and the compositions of various oils as a function of asphaltenes content on the 17 destabilization of the aqueous film separating the oil from substrate rock surface of carbonate using aqueous phases such 18 brine and carbonated water. The contact angles as a function of time were measured using brine and carbonated water 19 and two types of crude oils on four types of rock samples. Once the exact contact angle has been determined, the 20 compositions of various oils, based on asphaltenes contents, were characterized to investigate the role of oil composition 21 on the destabilization of the aqueous film separating the oil from rock surface. Interfacial tensions of brine and crude oils 22 were also measured. Four types of rock samples from carbonate reservoirs, with different compositions, selected based 23 on XRD results were: (1) 100% Dolomite D (100), (2) 100% Calcite C (100), (3) 67% Dolomite + 33% Calcite (D67 + 24 C33), and (4) 37% Dolomite + 63% Calcite (D37 + C63). Two types of crude oil were used based on asphaltenes content 25 obtained using SARA analysis. The contents of asphaltenes for the crude-1 and crude-2 were 11.6 and 6.4 wt% and 26 represented as (I-11.6) and (II-6.4), respectively. In this study, crude oil/brine/carbonate systems showed that (D37 + 27 C63) gave the lowest contact angle value of 67 o with 6.4 wt% of asphaltenes content (II-6.4), and D (100) gave the highest ACS Paragon Plus Environment Energy & Fuels 2 1 adhesion tension was shifting to positive directions as degree of water wetness was increasing. This behavior was mainly 2 due to the effect of type-II crude oil. 3 The novelty of this study stems from studying the effect of rock mineralogy based on Dolomite and Calcite distribution 4 and oil composition based on asphaltenes content in wettability alteration using aqueous phases such as brine and 5 carbonated water. The results of both contact angle and IFT were implemented in adhesion tension using Thomas Young 6 equation (Adamson, 1982) as an alternative approach in defining surface wettability. This study will provide a better 7 understanding of mineralogy/fluid/ interaction which is very crucial in the optimization of water injection and wettability 8 reversal during enhanced oil recovery process.