Reservoir Wettability Research Articles

CO2-foam flood with wettability alteration for oil-wet carbonate reservoirs

Carbon dioxide (CO2) flooding in carbonate reservoirs often suffers from poor sweep efficiency, attributed to unfavorable mobility ratio, gravity segregation, and reservoir heterogeneity. CO2-foam injection is a promising strategy to control CO2 mobility. The stability of CO2-foam is affected by reservoir wettability. This study aims to systematically investigate the effectiveness of CO2-foam flood coupled with wettability alteration in an initially oil-wet carbonate rock at a pressure below the minimum miscibility pressure. Three types of surfactants, including a nonionic surfactant Soloterra 843, a cationic surfactant CETAC-30, and a zwitterionic surfactant LMDO, were evaluated as potential foaming agents. Contact angle tests were conducted to assess the wettability alteration capability of these surfactants. Bulk foam stability tests and foam rheology tests were conducted under reservoir conditions. Finally, foam core flood experiments were performed using oil-wet carbonate core samples. Results from contact angle experiments indicated that only CETAC-30 was effective at altering rock wettability from oil-wet to water-wet by removing the negatively charged organic acid components from the rock surface. Foam stability and rheological tests revealed that LMDO exhibited highly stable CO2-foam in the absence of crude oil. However, the presence of crude oil adversely affected CO2-foam stability for all the surfactants. Core flooding experiments demonstrated that injecting wettability alteration surfactant, CETAC-30, in form of foam could not only alter the wettability of rocks, but also enhance the foam strength. Continuous gas injection (without foam) increased oil recovery by 14.4 % due to the near-miscibility of CO2 and oil. Both CETAC-30 and LMDO surfactants increased the oil recovery by about 35 % after waterflood, but the wettability altering surfactant showed the highest mobility reduction factor (MRF). These findings provide valuable insights into the complex interplay between near-miscibility, wettability alteration and foam strength in carbonate reservoirs, offering a basis for optimizing CO2-foam flooding strategies for enhanced oil recovery and carbon sequestration.

Mechanism study on the influence of wettability on CO2 displacement of shale oil in nanopores

A four-phase model of an oil–gas-water-wall system was constructed using the molecular dynamics simulation method. On this basis, the effect of shale reservoir wettability on the mechanism of CO2 flooding of oil will be investigated. The study found that in hydrophilic and mixed wetting systems, the front of the CO2 molecules had a semilunar shape. In lipophilic systems, however, it advanced as a whole. In addition, water molecules in the mixed wet system will form a water bridge, preventing the forward movement of CO2 molecules. CO2 molecules can easily displace oil molecules in pores of different wettability, but cannot remove the water molecules adsorbed on hydrophilic and mixed wetting systems. Oil molecules interact weakly with the hydroxyl group on the wall, but strongly with the methyl group on the wall. CO2 molecules interact strongly with both the methyl and hydroxyl groups on the wall. The difficulty of CO2 in displacing shale oil in different wetting systems is ranked in the following order: mixed wetting system (41.90 %), lipophilic system (91.51 %), hydrophilic system (98.77 %). Additionally, the storage efficiency of the three nanopores for CO2 was 50.53 %, 77.53 %, and 74.24 %, respectively. The research results can provide theoretical support for the development of CO2 in shale reservoirs.

Flow unit classification and characterization with emphasis on the clustering methods: a case study in a highly heterogeneous carbonate reservoir, eastern margin of Dezful Embayment, SW Iran

Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs.

Effects of nanoactive fluids on water wettability reversal of shale: Implications for CO2 geo-sequestration

CO2 geo-sequestration (CGS) is crucial in tackling global climate change, and the safety of CO2 storage within the reservoir is intricately linked to wettability. The utilization of nanofluids-surfactants for adjusting reservoirs’ wettability has emerged as a promising approach to enhance the security of CGS. However, the mechanism underlying their impact on reservoir wettability and carbon sequestration remains elusive. Regarding nanoactive fluid (ASNF) compounded with nano-SiO2 and AOS, to explore its potential for wettability reversal of CO2-exposed shale under in situ conditions, comparative experiments were conducted with Longmaxi Formation shale as the subject. The chemical structures and microstructures of shale before and after the experiments were comprehensively characterized. The results showed that a maximum of 67.93 % enhanced the water wettability of samples co-treated with ASNF and ScCO2. The primary reason for shale wettability reversal was increased hydrophilic chemical groups and enhanced interaction energy between organic matter and water molecules, stemming from nanoactive particle retention on the shale surface. The alteration in wettability decreased the mobility of CO2 and increased the distribution of surface water films, enhancing the carbon sequestration capabilities of the trapping mechanism. These findings provided an important foundation for improving the effectiveness and safety of CGS in shale reservoirs.

Comparative study on pore-connectivity and wettability characteristics of the fresh-water and saline lacustrine tuffaceous shales: triggering mechanisms and multi-scale models for differential reservoir-forming patterns

Although particular attention has been paid to responses of hydrocarbon storage and percolation capacity to the devitrification concerning lacustrine tuffaceous shale reservoirs in recent years, there is still a lack of systematical and comparative investigation on differential patterns and potential triggering mechanisms concerning development of the pore-microfracture systems and characteristics of surface wettability between the fresh-water and saline lacustrine settings, which is of considerable importance in fully understanding of genesis and spatial distribution of dessert reservoir intervals of tuffaceous shale reservoirs, and to provide further conceptual basis for deciphering shale-oil movability of saline lacustrine fine-grained mixed sedimentary sequences. In this study, tuffaceous shales from both the Upper Triassic Yanchang Formation in the Ordos Basin and Middle Permian Jingjingzigou Formation in the Junggar Basin are targeted to unravel the differential behavior of tuff devitrification and potential impacts on reservoir wettability and pore connectivity concerning fresh-water and saline lacustrine settings, and we present new results here from integrated analyses and combined interpretation of FE-SEM, Image Pro Plus (IPP) software image processing, contact angle and spontaneous imbibition experiments. In view of comparative analysis from representative samples, the tuffaceous shales from saline lacustrine environments are characterized by well-developed intergranular-intercrystalline and dissolution pores, and inorganic microfractures, generally yield a higher plane porosity of representative pore-fracture spaces and spontaneous imbibition slopes, a relatively lower average of n-decane contact angles and corresponding wettability parameters. The saline lacustrine tuffaceous shales are thus suspected to have undergone more intense devitrification resulting in a higher amount of devitrification and associated dissolution pores, and a relatively better connectivity between isolated micropore systems with adjacent microfractures. This would significantly facilitate the interface wettability reversal and occurrence of movable hydrocarbon fluid in microscopic reservoir spaces. Finally, a comprehensive and conceptual model is established illustrating the effects of differential devitrification on reservoir-forming patterns concerning tuffaceous shales developed in the fresh-water and saline lacustrine settings, respectively. These findings are of great theoretical and practical significance to enrich theory of high-quality reservoir formation and shale-oil accumulation in saline lacustrine tuffaceous shale reservoirs, and lay the foundation for guiding efficient exploration of continental fine-grained mixed sedimentary sequences.

Nanofluid flooding as a method of enhancing oil recovery: mechanism, advantages

Relevance. The fact that with the help of modern methods of increasing oil recovery, it is possible to extract no more than 34 % of oil from the initial recoverable reserves. Therefore, modernization of technologies for tertiary impact on the reservoir as one of the possible ways of developing this area is required. It is possible to use nanoparticles in order to increase the oil recovery coefficient by displacing residual and hard-to-recover oil. Technologies with the use of nanoparticles have a number of significant advantages over the already traditional polymer, alkaline and surfactant flooding. Nanofluidic flooding allows increasing the oil recovery coefficient. The paper considers the mechanisms of action of nanoparticles contributing to oil recovery, the relationship of the effectiveness of flooding from the reservoir temperature, pH, water mineralization and wettability of the reservoir rock surface. These mechanisms are required for identifying limitations of the applicability of nanofluids, the possibility of their modification, in order to improve the properties and eliminate the disadvantages of nanofluid flooding. The effect of the chemical nature of nanoparticles, their size, surface charge, isoelectric point and concentration on rock, reservoir fluids and the efficiency of hydrocarbon extraction is considered in detail. Attention is also focused on the latest modern trends in the development of nanofluidic flooding technology. Aim. To conduct a comprehensive analysis of nanofluidic flooding as a method of increasing oil recovery. Objects. Chemical methods of enhancing oil recovery, nanofluidic flooding. Methods. Analysis of current publications on the research topic. Results. The factors influencing the effectiveness of the use of nanofluids as a method of increasing oil recovery and the mechanisms of the impact of nanoparticles on oil reservoirs are formed, promising directions for the development of nanoparticle technology are identified.

Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection

Improved and efficient recovery methods are investigated as possible candidates to arrest the production decline and to improve the injection capacity in hydrocarbon fields in Lithuania. The data show that the Cambrian reservoirs in Lithuania are mixed to oil-wet in nature, which results in poor water-flooding efficiency. Wettability alteration could help in improved water injection and, at the same time, it could help recover additional oil from the residual oil saturation zone of the reservoir. In this paper, a screening exercise is conducted to help alter reservoir wettability, improve water injection efficiency, and to improve oil recovery. Analytical and machine-learning supported methods are used for screening. Based on the screening results, dilute surfactant-based injection techniques are suggested as a potential method to improve injectivity and, thereby, recovery from the field. An initial experimental analysis targets the wettability of the rock from the field, followed by testing for wettability-altering surfactants. Based on the findings of the screening study and experimental analysis, it is recommended that we initiate a core flooding experimental program to investigate wettability changes and enhance injection and recovery from the field.

Experimental Evaluation of CO2-Soluble Nonionic Surfactants for Wettability Alteration to Intermediate CO2-Oil Wet during Immiscible Gas Injection

Summary The change in wettability of limestone reservoirs from oil-wet toward gas-wet can enhance crude oil production during immiscible CO2 injection. Therefore, in this research, we investigated the impact of wettability alteration to CO2-wet on oil recovery factor via dissolution of fluorine-free, CO2-philic, nonionic surfactants such as C4(PO)6 and C41H83O19 in CO2. Based on the cloudpoint measurements, the dissolution pressures of nonionic surfactants in supercritical CO2 ranged between 2,100 psi and 2,700 psi (below the reservoir pressure, i.e., 3,000 psi) at reservoir temperature, 65°C; these pressures are commensurate with CO2-enhanced oil recovery (EOR) pressures. Also, the C4(PO)6 and C41H83O19 can reduce the CO2-oil interfacial tension (IFT). Moreover, the CO2/C4(PO)6 and C41H83O19 solutions can change the limestone wettability from strongly oil-wet (Θ ~ 20o) to intermediate CO2/oil-wet (Θ = 95o and 110o) at reservoir conditions. The relative permeability curves also confirmed it by changing the curvature to the left and decreasing the residual oil saturation in both cases of CO2/C4(PO)6 and C41H83O19 solutions. The 20.8% and 13.1% additional oil recoveries were achieved during the 30,000 ppm CO2/C4(PO)6 and C41H83O19 solution scenarios, respectively, relative to the pure CO2 injection scenario. These nonionic surfactants are not able to make CO2-in-oil foam; therefore, wettability alteration and perhaps IFT reduction are the dominant mechanisms of EOR induced by the dissolution of nonionic surfactants in CO2, instead of CO2 mobility control. Consequently, the dissolution of fluorine-free, oxygenated, CO2-philic, nonionic surfactants (such as C4(PO)6 and C41H83O19) in CO2 at 30,000 ppm concentration can be a well-qualified candidate for altering the limestone wettability to intermediate CO2-oil-wet during the immiscible CO2 injection.

Study on the Influence of Reservoir Wettability on Shale oil Flow Characteristics by Molecular Dynamics Simulation

Study on the Influence of Reservoir Wettability on Shale oil Flow Characteristics by Molecular Dynamics Simulation

An integrated approach to the substantiation of the boundary values and the assessment of the character of saturation in the deposits of the Tyumen formation

Background. The Tyumen formation is characterized by the complexity of the structure of deposits and consists of the sediments of different facies groups. To build hydrodynamic models, improve the development system and identify prospective zones, the conditions of sedimentation must be taken into account. Objective. Increasing the reliability of reservoir permeability assessment and clarifying critical resistivities when assessing the nature of saturation, which requires new approaches to petrophysical modeling. Materials and methods. The work uses the results of core studies and interpretation of well-logging data for the JV2 formation considering the facies. Results. The wettability of extracted and nonextracted samples is studied, the dependence of the saturation parameter on the water saturation coefficient is corrected taking into account the wettability of reservoirs, and the relative phase permeabilities are calculated for drainage conditions in the “oil–water” system. Conclusions. An integrated approach makes it possible to clarify the values of permeability, critical resistivities and oil and gas saturation of reservoirs, which can be used to identify prospecting zones when drilling new wells.

Ripening of Capillary-Trapped CO2 Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability

Ripening of Capillary-Trapped CO₂ Ganglia Surrounded by Oil and Water at the Pore Scale: Impact of Reservoir Pressure and Wettability

Effect of wettability on fracturing fluid microscale flow in shale oil reservoirs

The wettability of shale reservoirs has an important influence on the flow of external fluids. In this paper, the effect of wettability on the self-absorption of hydraulic fracturing fluid under different pore size conditions is first analyzed. Then, the mechanism of the influence of wettability pore size on the flow coefficient is elucidated. The results show that (a) as the pore size decreases, the importance of various forces acting on the fluid during the flow process changes, and the solid-liquid interaction will greatly affect the fluid flow in the nanopore. (b) When the radius is 5, the flow enhancement increases from 0.6331 to 0.998 as the radius increases from 0 to 3.141594.(c) The shale inorganic material contains a variety of minerals, and the interaction forces between different mineral surfaces and water molecules are different, resulting in different apparent viscosities.

Wettability evaluation of shale oil reservoirs and its impact on the post-fracturing shut-in duration of horizontal wells: a quantitative study for Ordos Basin, NW China

Shale oil development in Ordos Basin, China, primarily relies on the displacement of crude oil during the post-fracturing shut-in stage (PFSIS) of horizontal wells. Reservoir wettability significantly influences the shut-in duration and even the development approach. However, due to strong heterogeneity and super tight characteristics, the reservoir usually shows an mixed wettability, and it was usually hard to differentiate the wettability in different pore sizes. With this in mind, this study focuses on core samples from shale oil reservoir in the Longdong region of the Ordos basin to quantitatively analyze the reservoir wettability. Amott method combined with nuclear magnetic resonance is adopted in the paper to meed this end. And the optimal post-fracturing shut-in duration for Huachi and Heshui areas in the Longdong region are determined based on both wettability and field practice analysis as well as numerical simulations. Qualitative wettability evaluation reveals that the reservoir in the Longdong region is weakly oil-wet (oil-wet pores account for 58.9% and water-wet pores for 41.1%), and that larger pores are more water-wet, while smaller pores are more oil-wet. Field practice observes a noticeable two-stage decline in wellhead pressure, with pressure drop rates and water content decline rates following the order of neutral reservoir > weakly oil-wet reservoir > oil-wet reservoir during the post-fracturing shut-in stage. Numerical simulations indicate that the determination of the optimal post-fracturing shut-in duration for horizontal wells should consider reservoir properties, wettability, and injection volume. The final optimal shut-in durations for the Huachi and Heshui areas in the reservoir are determined to be 36 days and 43 days, respectively. Our study qualitatively distinguishes the wettability in different pores sizes and thus determines reasonable post-fracturing shut-in durations in different areas in Longdong region. The research has major implication for building a realistic method of wettability analysis in shale or tight oil reservoir.

Nuclear magnetic resonance experiments on the time-varying law of oil viscosity and wettability in high-multiple waterflooding sandstone cores

A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2 spectrum, and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance (NMR) experiments of high multiple waterflooding. A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores. The remaining oil viscosity in the core is positively correlated with the displacing water multiple. The remaining oil viscosity increases rapidly when the displacing water multiple is low, and increases slowly when the displacing water multiple is high. The variation of remaining oil viscosity is related to the reservoir heterogeneity. The stronger the reservoir homogeneity, the higher the content of heavy components in the remaining oil and the higher the viscosity. The reservoir wettability changes after water injection: the oil-wet reservoir changes into water-wet reservoir, while the water-wet reservoir becomes more hydrophilic; the degree of change enhances with the increase of displacing water multiple. There is a high correlation between the time-varying oil viscosity and the time-varying wettability, and the change of oil viscosity cannot be ignored. The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott (spontaneous imbibition) wettability index, which agrees more with the time-varying law of reservoir wettability.

Asphaltene Adsorption on Solid Surfaces Investigated Using Quartz Crystal Microbalance with Dissipation under Flow Conditions.

Asphaltenes can cause operational challenges in petroleum production facilities and adversely affect production by adsorption on mineral surfaces and alteration of the oil wettability of reservoirs. Therefore, understanding asphaltene adsorption mechanisms and their effects is crucial to improving the efficiency of oil production and reducing costs. In this study, we focus on understanding the impact of asphaltene concentration and the depositing environment of asphaltene adsorption on solid surfaces using the quartz crystal microbalance with dissipation (QCM-D) technique. The initial and long-term kinetics of adsorption at different concentrations were examined on three different solid surfaces including silicon dioxide to represent quartz mineral, stainless steel, and gold. The frequency-dissipation data showed evidence of monolayer adsorption initially, followed by multilayer formation. At short times, the adsorbed mass increased linearly with time, suggesting that the process was kinetically controlled rather than diffusion-controlled. The results were reproducible and did not depend on convection velocity but did depend on the surface material. At later stages, the monolayer development appeared to follow the random sequential adsorption (RSA) theory. Once multilayer adsorption commenced, the rates agreed well with the two-layer model of Zhu and Gu, 1990. The impact of asphaltene adsorption on the wettability of the surface was examined using contact angle studies, which showed decreasing water wettability with an increase in the adsorbed mass. The contact angle of water after 12 h of adsorption leveled off at around 100° on all three surfaces. Contact angle measurements were also used to evaluate if brine salinity causes the wettability alteration of surfaces with the adsorbed asphaltene. The results indicate that at 3% NaCl solution, the contact angle decreased only slightly by less than 2°.

Nuclear magnetic resonance study on wettability of shale oil reservoir

In order to identify and evaluate reservoir wettability, so as to select suitable mining methods to improve oil recovery, wettability evaluation through one-dimensional (1D) and two-dimensional (2D) nuclear magnetic resonance (NMR) technology combined with physical simulation experiments was carried out in this study, and the feasibility of the experimental method was verified by contact Angle method. According to the principle of hydrophilic inorganic content and hydrophobic organic content of shale, the wettability can be evaluated through vacuum self-imbibition oil and self-imbibition water physical simulation experiments combined with 1D NMR technology, that is, total water absorption can be considered as inorganic content, organic content can be obtained by subtracting total water absorption from total oil absorption, and adsorbed oil content can be obtained by subtracting pore volume from total oil absorption. In addition to the wettability measurement by contact Angle method to verify the experimental method, the occurrence ratio of adsorbed oil can also be verified twice by 2D NMR spectrum. The results show that the error between the proportion of adsorbed oil measured by 2D NMR spectrum and that measured by self-imbibition method is within 4%. In the saturated oil-bound water state, the bound water is within the relaxation interval of 1<T1<10 ms and 1<T2<10 ms, and the oil signal is within the relaxation interval of T1>10 ms and T2>10 ms. And the relaxation time of aqueous phase moved to the right compared with that in the saturated water state, the interaction force between water and the pore wall was weakened, showing the characteristics of free fluid, and the rock sample became oil-wet, which was consistent with the wettability results measured by contact Angle. Therefore, the wettability of rock samples can be evaluated by 1D NMR technique combined with vacuum imbibition method, or by analyzing the changes of NMR spectra of aqueous phase in completely saturated water and saturated oil-bound water.

Evaluation of the polymer hydrogels as a potential relative permeability modifier

AbstractExcessive water production poses a significant challenge in the oil industry, especially in Pre‐salt carbonate reservoirs, leading to reduced oil recovery, corrosion, and well abandonment. We explore the potential of polymeric preformed particle gels (PPGs) as innovative relative permeability modifiers (RPMs) for carbonate reservoirs. RPMs involve applying polymeric hydrogels to alter reservoir wettability, reducing water flow while enhancing oil productivity. PPGs offer a promising surface‐based production alternative with improved control and minimized formation damage compared to traditional in‐situ gels. We conducted crosslinking experiments using poly(acrylamide‐acrylic acid‐2‐methyl propane sulfonate) terpolymer (AM‐AA‐AMPS) and aluminum (III) ions, assessing their impact on hydrogel properties. We also investigated the swelling behavior of these hydrogels and their interactions with rock samples. Results showed that crosslinking significantly affects PPG viscoelastic properties and swelling behavior. Adsorption tests revealed the formation of a polymeric film on rock surfaces, potentially altering wettability. Contact angle measurements demonstrated PPGs' ability to shift rock wettability, particularly in carbonate samples, from strongly oil‐wet to water‐wet conditions. This study underscores PPGs' potential as RPMs, offering valuable insights into improving oil extraction efficiency and addressing water production challenges in the industry.

Nanoemulsions stabilized by nonionic surfactants to promote spontaneous imbibition in ultra-low permeability reservoirs: performance evaluation and mechanism study

Nano-emulsions stabilized by nonionic surfactants have the characteristics of ultra-low interfacial tension (IFT) and altered wettability in ultra-low permeability reservoirs. Thus, in this work, a new nanoemulsion is proposed to enhance spontaneous imbibition recovery in ultra-low permeability reservoirs. The nanoemulsion is prepared using n-dodecane, Tween-20, and coconut oil acid diethanolamine n-amyl alcohol. The effects of temperature and salinity on particle size, IFT, and wettability alteration performance of the nanoemulsions were systematically studied. Experimental results show that the particle size of nanoemulsions increases with salinity, and the highest level is up to 100 nm, while an increase in temperature is beneficial to the formation of smaller nanoemulsions. The IFT of the nanoemulsion system can be reduced to an ultra-low level (10–3 mN/m) when the salinity is lower than 50,000 mg/L. As for the wettability alteration property of a nanoemulsion system, an increase in temperature can improve its performance, but variations in salinity seldom have any effects. At 56 °C and 30,000 mg/L salinity, the spontaneous imbibition recovery of 1.00 wt% nanoemulsion can reach 53.8% under the synergistic effect of three mechanisms: extremely small droplet size, excellent wettability alteration performance, and ultra-low IFT. These three mechanisms work together to significantly improve the displacement efficiency of ultra-low-permeability reservoirs.

Effect mechanism of wettability on CO2 replacement brine in nanopores

The mechanism of using CO2 to replace brine in nanopores is still unclear, and the influence of the wettability of pore walls on the interfacial effect needs to be improved. In this study, the effect of wettability in tight sandstone reservoirs on CO2 replacement brine in nanopores was probed through molecular dynamics simulations. The results showed that the replacement front of CO2 molecules was meniscus shaped in hydrophilic and amphipathic systems, while it advanced as a whole in lipophilic systems. When CO2 replaced brine in nanopores, the interaction energies of the H2O and CO2 molecules near the pore walls with the pore walls were much greater than those of molecules in the centers of the pore channels·H2O molecules had strong interactions with the hydroxyl groups on the pore walls but weak interactions with the methyl groups on the pore walls, while CO2 molecules had strong interactions with both hydroxyl and methyl groups. Water films were always present on the hydrophilic pore walls to separate CO2 molecules from the pore walls, while the H2O molecules could be basically replaced in the lipophilic pore channels. CO2 molecules could easily strip the H2O molecules around the hydrophobic groups on the amphipathic pore walls, but they could not replace the H2O molecules around the hydrophilic groups on the amphipathic pore walls. During the process of CO2 replacement brine in nanopores, the interaction energies of the H2O molecules with pore walls dominated in hydrophilic and amphipathic systems, which were much greater than the energies of the CO2 molecules with H2O molecules and the CO2 molecules with pore walls. However, in the lipophilic system, the difference in interaction energy between different components was less. The results of this research could serve as a reference for understanding the mechanism of CO2 storage in tight sandstone reservoirs.

Molecular dynamics simulation of surfactant induced wettability alteration of shale reservoirs

Shale oil has recently received considerable attention as a promising energy source due to its substantial reserves. However, the recovery of shale oil presents numerous challenges due to the low-porosity and low-permeability characteristics of shale reservoirs. To tackle this challenge, the introduction of surfactants capable of modifying wettability has been employed to enhance shale oil recovery. In this study, we perform molecular dynamics simulations to investigate the influence of surfactants on the alteration of wettability in shale reservoirs. Firstly, surfaces of kaolinite, graphene, and kerogen are constructed to represent the inorganic and organic constituents of shale reservoirs. The impact and underlying mechanisms of two types of ionic surfactants, namely, the anionic surfactant sodium dodecylbenzene sulfonate (SDBS) and cationic surfactant dodecyltrimethylammonium bromide (DTAB), on the wettability between oil droplets and surfaces are investigated. The wettability are analyzed from different aspects, including contact angle, centroid ordinates, and self-diffusion coefficient. Simulation results show that the presence of surfactants can modify the wetting characteristics of crude oil within shale reservoirs. Notably, a reversal of wettability has been observed for oil-wet kaolinite surfaces. As for kerogen surfaces, it is found that an optimal surfactant concentration exists, beyond which the further addition of surfactant may not enhance the efficiency of wettability alteration.