Rock Surface Properties Research Articles

Quantitative Characterization of Adhesion Work on Shale Surfaces and Discussion on the Influence of Roughness Based on Atomic Force Microscopy (AFM).

Adhesion is an intrinsic property of rocks and liquids. Investigating the factors contributing to its formation and the mechanisms governing its action is crucial for elucidating the adhesion work between solids and liquids. The adhesion work, serving as a parameter that characterizes the energy changes during the solid-liquid contact process, is a vital tool for probing this phenomenon. However, conventional measurements of the adhesion work are significantly influenced by surface roughness and fail to differentiate local variations in the adhesion performance. This limitation obscures our understanding of the primary adsorption sites and mechanisms between solids and liquids, posing significant challenges to the study of rock surface properties. In this study, in conjunction with scanning electron microscopy and contact angle analyses, we elucidated for the first time the locations where voids form during the solid-liquid contact process, the lithological composition of rough areas, and their impact on the adhesion work between water/oil and the surfaces. Additionally, employing atomic force microscopy (AFM), we examined the variations in water/oil-solid adhesion work across different characteristic regions, thereby characterizing the overall hydrophilic/hydrophobic properties of the rock core. Specific conclusions are as follows: (1) A negative correlation exists between roughness and the contact angle adhesion work, with heterogeneity impeding liquid-rock contact; (2) By comparing the strength of water-solid/oil-solid adhesion work within localized areas, we delineated the adhesion work characteristics of samples and their primary generation sites, with oil-solid adhesion work in target blocks predominantly originating from quartz, clay minerals, and organic matter; (3) The influence of pore throat development on the overall adhesion work of samples was clarified, demonstrating that an increase in the proportion of internal rock pores enhances the surface oil-solid adhesion work; (4) A dimensionless wetting index I was established to mitigate the impact of roughness on the expression of adhesion work, exhibiting a strong correlation with traditional evaluation methods.

Nanotechnology Applications in Enhanced Oil Recovery (EOR)

Enhanced Oil Recovery (EOR) techniques are crucial for maximizing crude oil extraction from reservoirs, especially when traditional methods leave significant amounts of oil untapped. Recent advancements in nanotechnology have introduced innovative solutions to longstanding challenges in the oil industry. This research paper explores the application of nanotechnology in EOR, emphasizing the unique properties of nanoparticles that make them highly effective in this context. Nanoparticles, defined by their nanometer-scale dimensions, exhibit high surface area to volume ratios, quantum effects, and enhanced reactivity. These properties enable various mechanisms in EOR, including improved wettability, reduction in interfacial tension, enhanced thermal stability, selective plugging and fluid diversion, and catalytic effects. The study details how silica and titanium dioxide nanoparticles can modify rock surface properties, leading to better water imbibition and oil displacement. It also discusses how surfactant-coated nanoparticles can reduce the interfacial tension between oil and water, facilitating easier oil flow. Furthermore, the research highlights the role of metal oxide nanoparticles, such as aluminum oxide and zinc oxide, in enhancing thermal conductivity and stability during thermal EOR methods like steam flooding. The ability of polymer-coated nanoparticles to selectively plug high-permeability zones and redirect injection fluids is examined, demonstrating how this can lead to a more uniform sweep and higher oil recovery. The catalytic properties of certain nanoparticles, such as iron oxide, are also explored for their potential to promote in-situ chemical reactions that generate gases aiding oil displacement. Field applications and case studies underscore the practical benefits of nanotechnology in EOR. Examples include the use of silica nanoparticles in Middle Eastern oil fields, polymer-coated nanoparticles in Canadian heavy oil reservoirs, and iron oxide nanoparticles in Indian oil fields. These case studies have shown significant increases in oil recovery rates and operational efficiencies. However, the research also identifies several challenges that must be addressed for the widespread adoption of nanotechnology in EOR. These include the high costs and scalability issues associated with nanoparticle production and deployment, potential environmental and health risks, and the need for customized solutions to cater to the unique conditions of different reservoirs. In conclusion, while nanotechnology presents promising advancements in EOR through various mechanisms, overcoming challenges related to cost, scalability, and environmental impact is crucial. As research progresses, nanotechnology is poised to play a vital role in enhancing oil recovery and meeting global energy demands.

Micro/nano structured oleophobic agent improving the wellbore stability of shale gas wells

Through embedding modified nano-silica particles on the surface of polystyrene using the method of Pickering emulsion polymerization, a kind of nano/micro oleophobic agent named OL-1 was developed. The effects of OL-1 on the rock surface properties and its performance in inhibiting the oil phase imbibition into the rock were explored. The performance and mechanisms of OL-1 in improving the wellbore stability of shale gas wells were evaluated and analyzed. OL-1 could absorb on the surface of the shale core to form a membrane with a micro-nano two-stage roughness, making the surface energy of the core decrease to 0.13 mN/m and the contact angle of the white oil on the core surface increase from 16.39° to 153.03°. Compared with the untreated capillary tube, when immersed into 3# white oil, the capillary tube treated by OL-1 had a reversal of capillary pressure from 273.76 Pa to -297.71 Pa, and the oil imbibition height inside the capillary tube decreased from 31 mm above the external liquid level to 33 mm below the external liquid level. The amount of oil invading into the rock core modified by OL-1 decreased by 64.29% compared with the untreated one. The shale core immersed into the oil-based drilling fluids with 1% OL-1 had a porosity reduction rate of only 4.5%. Compared with the core immersed in the drilling fluids without OL-1, the inherent force of the core treated by 1% OL-1 increased by 24.9%, demonstrating that OL-1 could effectively improve the rock mechanical stability by inhibiting oil phase imbibition.

Improving uniaxial compressive strength estimation of carbonate sedimentary rocks by combining minimally invasive and non-destructive techniques

Uniaxial compressive strength (UCS) is the most used parameter to measure rock strength. However, restrictions in sampling large volume of material, the need of very large set of results and onsite characterisation of UCS non-destructively are requirements in many scientific and engineering investigations. The estimation of UCS from a single non-destructive or minimally invasive technique (NDT) may result incomplete because each NDT is sensitive to different compositional and textural factors. This paper combines open porosity, P-wave velocity, Leeb hardness and micro-drilling resistance force to estimate USC for a wide range of carbonate sedimentary rock types with different petrographic characteristics. Results reveal that mineralogical composition significatively affects micro-drilling resistance force profiles and P-wave velocity values, especially for quartz-bearing rocks. In addition, texture controls substantially the reproducibility of tests sensible to rock surface properties, such as Leeb hardness and micro-drilling resistance force. Fifteen simple and multiple expressions for UCS are fitted. Linear expressions have shown better coefficients of determination (R 2 ) than non-linear equations because of the linearity shown by individual parameters. Curve fitting improves as the number of petrophysical parameters increase in the multiple linear regression analysis. The best correlation is found when the equation incorporates all the mechanical parameters obtained non-destructively as well as open porosity (R 2 = 0.910). Leeb hardness is always the most significant variable of the fitted regressions and its addition into multiple linear equations causes an increase of R 2 . Open porosity also improves R 2 whereas drilling force and P-wave velocity have a lower statistical weight in the expressions. The UCS estimation from all NDT, without considering open porosity, shows a good correlation (R 2 = 0.899), which presents the advantage that they can be obtained non-destructively with portable equipment and can provide a numerous set of results at relatively low cost. • Compositional and textural factors affect differently to the mechanical parameters. • Leeb hardness is the most significant variable in the fitted regressions. • The best UCS estimation incorporates all NDT parameters as well as open porosity. • Portability is one of the main advantages of NDTs.

Effect of carbon chain lengths of cationic surfactant on inhibition rate of acid-rock reaction

Reduce the rate of acid-rock reaction is a key problem in the acidizing field. In order to reduce the damage of adsorption of traditional gelled acid in carbonate porous media, and further reduce its damage to permeability of dense carbonate rock after stimulation. Cationic surfactants can change the surface properties of rocks and control the contact area between H+ and rock surface. In order to explore the effect of different carbon chain lengths of cationic surfactants on retarding properties of acid-rock reaction, the critical micelle concentration(Ccmc) and critical surface tension value(γcmc) of seven different carbon chain lengths of cationic surfactants are determined. The results indicate that Ccmc decreases significantly with the increasing of carbon chain length. The adsorption morphology of CnTAC(n = 8,10,12,14,16,18,22) species at the solid-solution interfaces is dominated by monolayer. On negatively charged calcite surface, a large number of cationic species RNH3+ can easily adsorb on abundant CO32− sites, which causes a significant increase of zeta potential for calcite. Meanwhile, the wettability of hydrophilic solid surface is modified from strongly hydrophilic to weakly hydrophilic after adsorption to control the surface rate of acid-rock reaction. The acid solution with a concentration of 1.02 × 10−2 mol/L C14TAC has the best retarded performance which the retardation rate is 71.01%. This research is helpful to understand the retarding performance of surfactant, improving the retarded acid system and the effect of carbonate reservoir stimulation.

Influence of the pore space structure and wettability on residual gas saturation

A significant part of hydrocarbon deposits in Russia is in the late stage of development. The distribution of residual oil and gas reserves is determined by the properties of the holding rocks. Estimating of deposits’ residual gas saturation is an important scientific task. The allocation of zones with the maximum undeveloped gas reserves will allow to select areas in long-developed fields for the intensification of production in the most efficient way. To search for such “sweet” zones, it is necessary to determine the factors that provide the value of the residual gas saturation. The reliance of the value of trapped in pores, residual gas saturation on such rock properties as pore space structure and wettability is studied in this article. The influence of formation pressure value and behaviour on making up of residual gas saturation during field development is not accounted in this work. The study of a wide collection of core sampled from productive deposits of the Orenburg oil and gas condensate field, the Vuktylskoe oil and gas condensate field, oil and gas field of Orenburg region, and also three areas in the East Caucasian petroleum province confirmed that the value of structure-trapped oil and gas saturation of carbonate and terrigenous rocks is directly proportional to the ratio of pore diameters and channels connecting them. Herewith the angular coefficient of the regression equation for this relationship for carbonate rocks directly depends on the quantitative characteristics of the predominant (relative) wettability. The obtained relationships make it possible to predict the value of residual gas saturation based on knowledge about the pore space structure and the surface properties of rocks.

What Controls Bedrock Shore Platform Hardness? A Field Study from South Africa

Knight, J. and Burningham, H., 2020. What controls bedrock shore platform hardness? A field study from South Africa. In: Malvárez, G. and Navas, F. (eds.), Global Coastal Issues of 2020. Journal of Coastal Research, Special Issue No. 95, pp. 537-541. Coconut Creek (Florida), ISSN 0749-0208.Bedrock shore platforms are common features along the Indian Ocean coast of South Africa but their properties and controls have not been well reported. This study presents high-resolution evidence for rock surface properties and hardness values from a sandstone platform at Morgan's Bay (Eastern Cape, South Africa) where the relative roles of environmental versus lithological factors on bedrock surface hardness can be evaluated. Results show that there is very little correspondence between rock hardness and either absolute platform elevation or distance from low water position of sea level. Two contrasting conceptual models are proposed to explain these results. One model proposes that a uniform geological control dominates, despite variations in environmental forcing. The alternative model considers that environmental controls such as waves and subaerial weathering do not significantly vary over the platform, despite any differences in platform relief and microenvironment. These different models can be used as testable hypotheses to evaluate the relative controls on, and thus interpretations of, measurements of rock surface hardness on shore platforms.

Understanding desorption of oil fractions from mineral surfaces

Separation of heavy hydrocarbons from mineral surfaces is highly dependent on the oil composition and their host rock surface properties. Herein, the petroleum is divided into SARA fractions (saturates, aromatics, resins, asphaltenes) to investigate their desorption behaviors on different types of mineral surfaces (silica (SiO2), kaolinite (Al2Si2O5(OH)4) and calcium carbonate (CaCO3)). The Quartz Crystal Microbalance with Dissipation (QCM-D) tests show that the saturates and aromatics could desorb from the mineral surfaces spontaneously even in water, while no desorption was observed for the asphaltenes and resins. Although the above desorption could be enhanced by alkaline or surfactant solutions, great difference still appears to different oil fractions. Oil characterization shows that the heavy fractions (i.e., asphaltenes, resins) possess richer acid groups than those of light fractions, allowing the stronger affinity of heavy fractions to the mineral surfaces through polar and chemical interactions. Additionally, the heavy fractions dominate in determining the desorption properties of bitumen (the mixed fractions), and lead to more significant wettability alteration to the mineral surfaces. Furthermore, the oil fractions desorption is also found to be highly influenced by the mineral types. Compared with silica, kaolinite has stronger affinity to the heavy oil fractions, leading to smaller amount of desorption. While on the calcium carbonate surface, less than 11% of the coated oil fractions are observed to be desorbed. Surface characterizations summarize that, due to the difference in mineral composition, the affinity of minerals to oil components in aqueous solutions is given as: calcium carbonate (positively charged calcium ions) > kaolinite (containing –AlOH, –SiOH groups and heavy metal elements) > silica (–SiOH group). The above results reveal the differences among bitumen subfractions and mineral types, allowing potential insights to the development of enhanced oil recovery, such as aqueous-nonaqueous hybrid extraction process, solvent extraction, CO2-enhanced oil recovery, etc.

Equation of State for Relative Permeability, Including Hysteresis and Wettability Alteration

SummaryCommercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation.This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.

Application of Acrylate Copolymers in the Drilling-in Completion Fluid for Low and Extra Low Permeability Reservoirs

To address the problems of current drilling-in fluids and the particularity of formation damage in low and extra low permeability reservoirs, two kinds of additives (fluoroacrylate polymer FCS-08 and acrylate polymer LCM-08) have been developed, and a novel approach, which combined wettability reversal, water lock prevention, and film-forming, has been put forward. By adding in the FCS-08 and LCM-8, drilling-in completion fluid characterized by “rock surface properties improvement” is invented. This drilling-in fluid had better effect on reservoir protection and achieved the “zero damage” near the borehole. The daily oil production has been increased by 20%.

Microscale Simulations of NMR Relaxation in Porous Media Considering Internal Field Gradients

Longitudinal and transverse nuclear magnetic resonance (NMR) relaxation signatures in porous rock were simulated on the microscale to examine and quantify how physical hydrologic parameters, such as rock‐surface properties and pore sizes, affect longitudinal and transverse NMR signals of real, complex media. Parameters studied were: magnetic field strength, rock susceptibility, pore coupling, and surface reactivity. Using the finite element method (FEM), simulations of the spatial‐ and time‐dependent magnetization evolution in arbitrary pore geometries, diffusion regimes, and heterogeneous distributions of rock surface properties, i.e., surface relaxivity, were compiled using an adapted generic diffusion model coupled with magnetic gradient field calculations. The numerical simulations were validated using analytical solutions that are available for simple pore geometries. We observed a pore‐size‐dependent ratio of transverse T2 and longitudinal T1 relaxation times, and thus a pore‐size‐related and rock‐susceptibility‐dependent effective transverse surface relaxivity was deduced. This can be used to improve estimates of pore sizes and thus of permeability from transverse NMR relaxometry measurements. Simulations of connected pore systems showed significant influences of interpore coupling at hydrologically relevant pore sizes, e.g., fine sands. Depending on the dominant diffusion regime, the typically heterogeneous distribution of surface relaxivities in rocks and sediments, i.e., geological noise, can lead to a significant underestimation of derived pore sizes and thus of permeability.

Effect of Drilling Fluids on Rock Surface Properties

Summary This paper discusses the wettability change induced by contact between porous media and drilling fluids and the possibility of eliminating such alterations by cleaning. Three porous media were studied (sandstone, shaly sandstone, and carbonate), as well as various drilling fluids (oil- and water-based). Initially strongly water-wet (hydrophilic) and initially neutral rock/oil/brine systems were evaluated. Wettability was estimated by a test based on spontaneous and forced displacement experiments. The results show that all the oil-based drilling fluids used induce a wettability change inasmuch as the rock is initially water-wet. The rock surface properties are observed to be affected at a distance > 0.6 in. [> 1.5 cm] from the rock/drilling-fluid interface. Cleaning procedures with toluene and methanol circulations can return the rock surface to the original wettability state, but the permeability remains affected. Water-based drilling fluids made no appreciable change in the wettability of the three initially highly hydrophilic porous media.