Influence of oil aging time, pressure and temperature on contact angle measurements of reservoir mineral surfaces

Silveira, Bruno Marco de Oliveira; Gioria, Rafael dos Santos; Florez, Jhonatan Jair Arismendi; Fagundes, Thais Bortotti; Silva, Mayara Antunes da Trindade; Skinner, Rodrigo; Ulsen, Carina; Carneiro, Cleyton de Carvalho; Ferrari, Jean

doi:10.1016/j.fuel.2021.122414

Cited by 6 publications

(3 citation statements)

References 30 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Figure shows the average CA results and standard deviations of 25 oil droplets for each treated and untreated aqueous solution on similar rock end pieces under ambient temperature and pressure. The variations of CA measurements are mainly due to the heterogeneity of the rock and aging time. − …”

Section: Resultsmentioning

confidence: 99%

Effects of Electro-Oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery

et al. 2022

View full text Add to dashboard Cite

Oil and gas industry has faced significant operational, economic, and environmental challenges in recycling produced water. The treatment of produced water is highly researched, but few studies have evaluated the performance of treated produced water when used for hydraulic fracturing and enhanced oil recovery (EOR) operations. In this study, we treated various aqueous solutions, including synthetic formation brine (FB), sodium chloride (NaCl), calcium chloride (CaCl2), and sodium sulfate (Na2SO4), using an electro-oxidation (EO) process. The brine properties, including density, surface tension (ST), oil–water interfacial tension (IFT), viscosity, and pH, were compared before and after the treatment. Then, we conducted systematic contact-angle (CA) measurements and spontaneous imbibition tests using treated and untreated brine to study the effects of water treatment on rock–fluid interactions and its impact on oil recovery. The experimental results show that the effect of the EO process on ST, density, viscosity, and IFT was insignificant. However, the CA results show that the treated FB, NaCl, and Na2SO4 solutions exhibit stronger wetting characteristics compared with the untreated ones, while the treated CaCl2 solution exhibit weaker wetting characteristics compared with the untreated ones. We hypothesized that the change in the wetting characteristics was due to the generated oxidants from the EO process. We added OH–, H+, hydrogen peroxide (H2O2), and sodium hypochlorite (NaOCl) into untreated brine to test this hypothesis and monitored the CA variations. The results suggest that H2O2 and OH– can alter the wettability to more water-wet conditions in the NaCl solution but not in the CaCl2 solution. Furthermore, NaOCl results in wettability alteration to more oil-wet conditions in NaCl and CaCl2 solutions. The change in wettability to more water-wet conditions is mainly the result of the oxidation of dissolved organic matters, and the change to more oil-wet conditions is the result of the dissolution of high-valence cations, causing the cation bridging effect.

show abstract

Section: Resultsmentioning

confidence: 99%

Effects of Electro-Oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery

et al. 2022

View full text Add to dashboard Cite

show abstract

“… 29 For the aging process, the rock slices were initially saturated with formation water under vacuum conditions. Subsequently, these slices were immersed in crude oil at 50 °C for 21 days to restore their original wettability; one can refer to the work of de Oliveira Silveira et al 30 for more details.…”

Section: Methodsmentioning

confidence: 99%

Experimental Investigation on the Interfacial Characteristics of Tight Oil Rocks Induced by Tuning Brine Chemistry

Cheng,

Tong,

Wang

et al. 2024

ACS Omega

View full text Add to dashboard Cite

Currently, research on enhancing imbibition oil recovery in tight oil reservoirs through the ion-tuning technique remains limited. Two critical parameters for capillary imbibition are the wettability and interfacial tension between oil and water. In this investigation, we manipulate the properties of two types of formation water for both aged and unaged samples by diluting brine and altering ion composition. Subsequently, we employ captive and pendant-drop methods to assess rock wettability and interfacial tension under varied brine conditions. Additionally, we elucidate the primary mechanisms underlying changes in rock wettability and interfacial tension. Meanwhile, we analyze capillarity characteristics and assess the relative significance of wettability and interfacial tension. Results indicate that there is a critical interfacial tension with progressive dilution of two types of formation water. However, modifying ion composition leads to a complex trend in interfacial tension, which can be explained qualitatively through the Gibbs adsorption isotherm. For unaged samples, the contact angle demonstrates a pronounced water-wet characteristic, showing a nonmonotonic trend with respect to dilution times. Remarkably, the rock surface exhibits the strongest water-wet, particularly evident in the case of FW-10, largely influenced by variations in interfacial tension. Conversely, aged samples demonstrate strong oil-wet, with a critical salinity resulting in the lowest contact angle, while altering brine ion types can alter rock wettability from strongly oil-wet to intermediate-wet, which is not sufficient to result in the wettability alteration. The removal of multivalent cations is proposed as the most effective method for wettability modification. Furthermore, capillarity variations among different brine cases are primarily contingent upon contact angle changes, and interfacial tension does not have a significant change when regulating the brine properties. Consequently, we emphasize the significance of wettability in the adoption of ion-tuned brine techniques for tight oil reservoirs. Overall, our study underscores the potential of reasonably regulating brine properties to enhance capillarity and, thereby, improve imbibition oil recovery.

show abstract

“…In order to clarify and evaluate the wettability of samples, many testing methods have been proposed by predecessors. The measurement of contact angles between the wall surface and liquid droplets has been the most widely used method to quantify surface wettability [27][28][29]. Contact angle measurement is a valuable and robust theoretical model; however, its initial application was focused on macroscopic wettability and is subject to limitations imposed by various external factors.…”

Section: Introductionmentioning

confidence: 99%

Mechanism and Quantitative Characterization of Wettability on Shale Surfaces: An Experimental Study Based on Atomic Force Microscopy (AFM)

Huo,

Sun,

Yang

et al. 2023

Energies

View full text Add to dashboard Cite

Wettability, as a vital tool for analyzing and describing oil flow, plays a significant role in determining oil/water relative permeability, residual oil distribution, and on–site recovery efficiency. Although the contact angle method is widely used for measuring wetting behavior, it is susceptible to the effects of surface roughness, oil–water saturation, and the distribution of mixed wetting within the range of droplet sizes. Additionally, millimeter–scale droplets fail to accurately represent the wetting distribution and the influencing factors at the micro/nano–scale. Therefore, this study presents a comprehensive investigation of the microstructure and wettability of shale samples. The characterization of the samples was performed using scanning electron microscopy (SEM) and atomic force microscopy (AFM) techniques to gain insights into their microscopic features, surface properties, and wettability. Results demonstrate the following: (1) Quartz and clay minerals tended to exhibit rough surface topography, appearing as darker areas (DA) under scanning electron microscopy (SEM). It is worth noting that plagioclase minerals exhibited brighter areas (BA) under SEM. (2) An increase in the content of minerals such as quartz and clay minerals was observed to decrease the surface oil wetting behavior. In contrast, plagioclase feldspar exhibited an opposite trend. (3) Based on the adhesive forces of the samples towards oil or water, a wetting index, I, was established to evaluate the wettability of shale at a microscale. The dimensionless contact angle W, obtained by normalizing the contact angle measurement, also consistently indicated oil wetting behavior. (4) By comparing the differences between I and W, it was observed that surface roughness significantly affected the behavior of water droplets. The presence of roughness impeded the contact between the solid and liquid phases, thus influencing the accuracy of the wetting results. Organic matter also plays a significant role in influencing surface wettability, and its distribution within the shale samples can lead to localized variations in wettability.

show abstract

Influence of oil aging time, pressure and temperature on contact angle measurements of reservoir mineral surfaces

Cited by 6 publications

References 30 publications

Effects of Electro-Oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery

Effects of Electro-Oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery

Experimental Investigation on the Interfacial Characteristics of Tight Oil Rocks Induced by Tuning Brine Chemistry

Mechanism and Quantitative Characterization of Wettability on Shale Surfaces: An Experimental Study Based on Atomic Force Microscopy (AFM)

Contact Info

Product

Resources

About