Wettability Of Reservoir Rock Research Articles

FORMULATING AND CHARACTERIZING AN OIL-IN-WATER PALM OIL FREE FATTY ACID-BASED NANOEMULSIONS FOR CRUDE OIL EXTRACTION PERFORMANCE

Nanoemulsion is a promising medium for chemically enhanced oil recovery (cEOR) due to its ability to reduce interfacial tension and modify the wettability of reservoir rocks. This work focuses on formulating stable oil-in-water (O/W) nanoemulsions through high-energy ultrasonication method, with oleic acid as the primary component and is stabilized with a non-ionic Tween 40 surfactant in distilled water. Systematic experimental designs, employing response surface methodology (RSM), were implemented to develop polynomial models for various responses related to the dynamic and stability properties, and crude oil extraction performance. The p-value indicator (p-value < 0.05) is utilized to assess the significance of the models and independent variables. Overall, the formulation for achieving the lowest surface tension involves 0.41 wt.% oleic acid mixed with 0.81 wt.% Tween 40 at 60 °C. Meanwhile, the highest viscosity attained with 1.0 wt.% oleic acid mixed with 1.0 wt.% Tween 40 at 30 °C. For stable nanoemulsion, the best conditions are 1.69 wt.% oleic acid, sonicated for 15 minutes at 25 °C. Additionally, an optimal condition for effective crude oil extraction is at nanoemulsion preparation with sonication time of 15 minutes and contact time of 12 hours in the immersion experiment. To this end, this work contributes valuable insights into the formulation and characterization of stable oleic acid O/W nanoemulsions for potential EOR applications. The findings enhance understanding of nanoemulsion properties and their potential as effective agents in crude oil recovery.

Influence of extractable organic components on shale wettability: Dongyuemiao member of Jurassic Ziliujing formation in the Fuxing area, Eastern Sichuan Basin

The wettability of reservoir rocks is a critical factor for the petroleum exploration and recovery, which plays an important role on relative permeability, capillary pressure, and ultimate recovery. This study aims to characterize the difference in wettability before and after soxhlet extraction, and reveal the influences of mineral composition, pore structure and extractable organic components on wettability of shales with different lithofacies. Several organic shale samples from the Dongyuemiao (DYM) section of the Jurassic Ziliujing (ZLJ) formation were collected to investigate the mineral composition, pore-size distribution, wettability characteristics and determine the main controlling factors on wettability alteration. Pore type and abundant are observed using argon ion polishing scanning electron microscopy. The pore volume (PV) and pore size distribution (PSD) characteristics before and after extraction were obtained using a combination of nitrogen physisorption and high-pressure mercury intrusion porosimetry (MIP). Spontaneous imbibition (SI) and nuclear magnetic resonance (NMR) experiments were used to investigate the wettability characteristics before and after extraction.Results show that clay, quartz and calcite are dominant minerals in the DYM shales, and three typical lithofacies are identified, including mixed shale (M), argillaceous shale (CM) and calcareous shale (C). Clay mineral interP pore is the dominant pore type in the DYM shales, followed by organic matter (OM) pore. Before the extraction, the DYM shale is more oil lipophilic, while its wettability alters slightly after the extraction. The M shales and C shales maintain lipophilic, while as the CM shales alters from oil wet to mixed wet. Samples with higher quartz have better connectivity of the hydrophilic and lipophilic pore networks, and carbonate minerals play an opposite role. During the extraction process, polar solvents could react with clay minerals to cause pore space expansion, which enhances the water wettability after extraction. Due to the low OM content and poor organic clay complex related pores in the study area, clay minerals have not significant correlation with oil wettability, but influence the water wettability. No correlation occurs between total organic carbon (TOC) content and oil/water wettability of shales before and after extraction. In comparison, macropore has a significant impact on water wettability, while micropore and mesopore play significant impact on oil wettability.

Surfactant technology for improved hydrocarbon recovery in unconventional liquid reservoirs: a systematic literature review

An unconventional liquid reservoir (ULR) is a type of underground geological deposit containing liquid hydrocarbons, such as crude oil, natural gas liquids, or condensate, not found in traditional oil and gas reservoirs. These formations have distinct properties that make oil and gas production more difficult than in typical reservoirs. Surfactants can be added to the fracking fluid to aid in the release of hydrocarbons. By reducing the amount of water and chemicals used in the process, surfactants can assist to reduce some of the negative environmental implications associated with fracking. In the current study, a systematic literature review was used to analyze and identify existing literature on surfactant technology in unconventional liquid reservoirs from the previous five years. 12 papers out of the 500 papers collected showed that studies had been performed and proved that surfactants can potentially increase the recovery of unconventional liquid reservoirs. The mechanism behind the positive outcome was concluded to be the alteration of wettability of reservoir rock and interfacial tension. Based on the conducted review, evaluation of the environmental impact from the use of surfactant and assessment of economic feasibility of surfactant technology in ULR could be the future research topics.

Study of Wettability Alteration of Hydrophobic Carbonate Rock by Surfactant-Containing Chelating Agent Solutions

Chelating agents’ application for well stimulation is gaining more and more interest, as they can perform under harsh conditions. However, the mutual influence of surfactants and chelating agents on the wettability alteration of hydrophobic carbonate rock under conditions of high-temperature well stimulation is relatively unexplored. This paper aims to study interfacial processes on the surface of hydrophobic rock in the presence of the EDTA-based chelating agent and surfactants of different classes. Cationic (cetyltrimethylammonium bromide, CTAB, and cetylpyridinium bromide, CPB), anionic (sodium dodecyl sulfate, SDS), and amhoteric (alkyldimethyl aminooxide, AO) surfactants were studied. Wettability alteration of model hydrophobic rock was studied under conditions specific to well stimulation. It was shown that chelating agent (CA) alone and its mixture with SDS could not lead to sufficient wettability alteration. CTAB, CPB, and AO were able to change the wettability effectively. A synergistic effect between CA and these surfactants was observed and a possible mechanism was proposed. AO was selected as the most promising surfactant. The influence of surfactant on the CA’s dissolution capacity towards carbonate rock was investigated; dissolution capacity strongly depends on wettability alteration. Finally, the effect of CA, AO, and their mixture on the wettability of aged reservoir rock was studied and the absence of negative effects was proven.

Experimental studies on effectiveness of graphene oxide nanosheets dispersion in water/aqueous PHPA for enhanced oil recovery

Nanoparticle application in enhanced oil recovery is emerging as a novel technology because of their unique characteristics, viz. reduction of IFT, wettability alteration, and stable dispersion in injection water and aqueous polymer solution. In the present study, graphene oxide nanosheets (GONs) are synthesized by modified Hummer's method. The nanosheets are characterized by FTIR, XRD and UV–vis spectroscopy analysis. The size of the nanosheets was confirmed by the AFM and HR-TEM imaging. The stability of nanofluid (NF) with dispersed GONs in the aqueous solution was confirmed by Turbiscan stability analysis, DLS studies and zeta-potential values (less than −34 mV). The experimental research reveals that NF alters the wettability of intermediate oil-wet sandstone reservoir rock with a reduction of contact angle from 112.4° to 17.2°. Further, it is observed that the IFT between oil (decane) and deionized water decreases from 42.34 mN/m to 32.76 mN/m for the NF system. It has been observed that the synthesized GONs can emulsify crude oil, which is also an important mechanism of EOR. The rheological studies show that GONs enhance the viscosity and viscoelastic properties of partially hydrolyzed polyacrylamide (PHPA) polymer. GONs form a robust three-dimensional network structure facilitated by hydrogen bonding with the PHPA polymer chain, which leads to the improvement of sweep efficiency. The core flooding experiment demonstrates that the incremental oil recovery over the conventional water flooding by GONs dispersed in the PHPA polymer with flooding is significantly higher (26% of original oil in place) than that of individual NF and polymer flooding.

Influence of anionic surfactant on stability of nanoparticles in aqueous solutions

Dispersion and aggregation of nanoparticles in aqueous solutions are important factors for safe and effective application of nanoparticles, for instance, in the oil industry. As conventional oil reserves are depleted, it is necessary to advance chemical enhanced oil recovery (cEOR) techniques to develop unconventional oil reservoirs. Nanoparticles modified by surfactants can be a promising reagent in cEOR. These nanomaterials can reduce interfacial tension and change the wettability of reservoir rock, which leads to an increase in oil recovery. However, the application of nanoparticles is limited by their substantial aggregation in aqueous solutions. The purpose of this work is to select nanoparticles for obtaining stable sols in water in the presence of an anionic surfactant and to optimize the conditions (pH) for further modifying the nanoparticles with the anionic surfactant. Sodium dodecyl sulfate (SDS) is used as an anionic surfactant. The aggregation of oxide and carbon nanoparticles in water and anionic surfactant solutions was studied by laser diffraction, dynamic and electrophoretic light scattering methods. Most of the studied nanoparticles in water form aggregates with bi-, three- and polymodal particle size distributions. TiO2 nanoparticles obtained by plasma dynamic synthesis form the most stable sols in anionic surfactant solutions. The range of 5–7 pH is defined as optimal for their modification with surfactants. The stability of carbon nanoparticles in aqueous solutions increases significantly in the presence of a surfactant. The obtained results form the basis for further research on the modification of marked nanoparticles in surfactant solutions.

Mechanism and Performance Analysis of Nanoparticle-Polymer Fluid for Enhanced Oil Recovery: A Review.

With the increasing energy demand, oil is still an important fuel source worldwide. The chemical flooding process is used in petroleum engineering to increase the recovery of residual oil. As a promising enhanced oil-recovery technology, polymer flooding still faces some challenges in achieving this goal. The stability of a polymer solution is easily affected by the harsh reservoir conditions of high temperature and high salt, and the influence of the external environment such as high salinity, high valence cations, pH value, temperature and its own structure is highlighted. This article also involves the introduction of commonly used nanoparticles, whose unique properties are used to improve the performance of polymers under harsh conditions. The mechanism of nanoparticle improvement on polymer properties is discussed, that is, how the interaction between them improves the viscosity, shear stability, heat-resistance and salt-tolerant performance of the polymer. Nanoparticle-polymer fluids exhibit properties that they cannot exhibit by themselves. The positive effects of nanoparticle-polymer fluids on reducing interfacial tension and improving the wettability of reservoir rock in tertiary oil recovery are introduced, and the stability of nanoparticle-polymer fluid is described. While analyzing and evaluating the research on nanoparticle-polymer fluid, indicating the obstacles and challenges that still exist at this stage, future research work on nanoparticle-polymer fluid is proposed.

Viscosity behavior for zirconia and γ-alumina nanoparticles in different electrolytic solutions: An experimental investigation

Viscosity modification of injected fluids is a vital mechanism for successful oil recovery from an oil reservoir. Various studies have demonstrated that nanoparticles (NPs) possess the tendency to alter the wettability of reservoir rocks, reduce the interfacial tension between injected fluids and crude oil, and modify the viscosity of injected fluids. Zirconia (ZrO2) and γ-alumina (γ-Al2O3) NPs have demonstrated huge prospects for enhanced oil recovery (EOR) in various studies. Recently, experimental investigations have attributed the viscosity behavior of silica nanofluids to the interaction between the ions of the silica NPs and electrolytes at the electrical double layer. Therefore, this study investigates the viscosity behavior of ZrO2 and γ-Al2O3 NPs with their increasing concentrations in different aqueous solutions present in reservoir brine by employing techniques such as dynamic light scattering and transmission electron microscopy in addition to viscosity and pH measurements at ambient conditions of approximately 25℃ and 1 atm. The viscosity behavior of spherical particles in suspensions is well suited for the viscosity profile of the nanofluids with increasing concentrations of ZrO2 and γ-Al2O3 NPs. The viscosity of the ZrO2 and γ-Al2O3 nanofluids containing the chloride salts increases in the order of Ca2+ > Na+ > K+ while those containing the sulfate salts increase in the order Mg2+ > Na+ > K+. Comparatively, the model proposed by Williams et al. predicts the viscosities of the electrolyte-based zirconia and γ-Al2O3 nanofluids with percentage absolute average deviation (%AAD) of 2.07 and 2.52 %, respectively, whereas those by Einstein’s model records %AAD of 3.15 and 3.68 %, respectively. The findings from this study provide experimental data and illuminate the understanding of the viscosity behavior of the nanofluids containing electrolytic ions and set the stage for further investigations, which are relevant for EOR purposes.

The Effect of Nano Heavy Metal Oxide Particles on the Wettability of Carbonate Reservoir Rock

Summary Production of oil from carbonate rocks is very challenging due to their inherent nature, such as detection, complex wettability, pore structure, and low recovery factor. Nanoparticles (NPs) are recognized as remarkable materials for a wide range of research and commercial applications due to their physical properties and characteristics. Extensive research in recent years has shown that nanoscience can provide great potential for the development of carbonate reservoirs and enhanced oil recovery (EOR). In this study, the carbonate core plug samples were prepared from an Iranian reservoir. At first, the wettability capacity of the core samples was evaluated. This process was carried out by evaluating wettability changes using the contact angle of base fluid and nanofluid. The potential of the NPs (ZnO, TiO2, and ZrO2) to change the wettability was experimentally tested in the loading NPs from 0.01 wt% to 0.5 wt% by the contact angle method. Wettability studies have shown that nanofluids can influence wettability variability from oil-wet to water-wet quality. About 0.05 wt% of NPs was found to be the optimal concentration to affect wettability change. The same behavior was observed for all nanofluids at the same NP loading; while TiO2 showed better performance with a sharp change from an oil-wet state (θ = 151.9°) to a water-wet state (θ = 111.3°), ZnO, and ZrO2 changed wettability to a moderately-wet condition (θ = 108.6° and 118.6°, respectively) at 0.05 wt% NP loading. We conclude that TiO2-based nanofluids have great potential as EOR agents, and TiO2 is very impressive in its strong water-wettability. The highest oil recovery in the optimal amount for all three nanofluids was obtained as 35.2%, 23.2%, and 25.6%, respectively, for TiO2, ZnO, and ZrO2 nanofluids. Furthermore, we considered the effect of nanofluids on the recovery performance of the brine/oil system for carbonate core samples. The results showed that nanofluids can significantly imbibe into the core sample, and as a result, the final oil recovery is significant.

Microscale Reservoir Wettability Evaluation Based on Oil–Rock Nanomechanics

Low oil production and rapid production decline epitomize the challenges of unconventional reservoir development. Rocks in the formation with micro-/nanoscale pore-throat units possess an immense surface area. Consequently, the wettability of rocks plays a crucial role in the relative permeability of oil/water, the injection pressure, the distribution and morphology of residual oil, and hence the ultimate oil recovery. Contact angle, as a frequently used method to evaluate wettability, is susceptible to oil-water saturation, imbibition, and surface roughness of rock slices. In addition, the measurement scale (droplet of several millimeters) does not match the flow scale (pore units in micro- or nanoscale). Therefore, this paper established a new wettability evaluation method based on oil–rock interaction. Molecular dynamics simulation results demonstrated that the interaction energy between the oil molecule and walls with different wettabilities shows a distinct discrepancy. Accordingly, nanomechanics by AFM was utilized to measure the oil molecule–pore wall interaction force. It was found that the interaction force increases with the augmented hydrophobicity of the pore wall due to hydrophobic force. In addition, the reservoir rock wettability index was defined using the oil–rock interaction force in the nanoscale. The wettability index has an excellent linear correlation with the intrinsic contact angle. The wettability evaluation method based on the oil–rock interaction force is more direct, facile, and rapid and overcomes the limitation of the traditional contact angle method.

A potential NMR-based wettability index using free induction decay for rocks

The wettability of reservoir rocks saturated with oil and water is one of the most important factors influencing petrophysics and oil recovery. Minerals with different wettability constitute the overall heterogeneous wettability in rocks. Variations in sample composition can be detected by nuclear magnetic resonance (NMR) measurements. In this paper, the method of using the magnetic susceptibility contrast between rock skeleton and saturated fluid to estimate wettability is proposed. The theoretical feasibility was firstly analyzed, and then the internal gradients caused by magnetic susceptibility contrasts were employed to interpret wettability alteration before and after ageing process in rocks. It was discovered that water and oil in the same pores experienced different internal gradients after ageing, which were associated with the differences in magnetic susceptibility contrasts. After that, the free induction decay measurement was performed to acquire magnetic susceptibility contrasts of artificial sandstone samples with the intermediate-wet condition. A refined NMR wettability index was presented and correlated with the Amott wettability tests. The experimental results demonstrate that the new method for determining wettability is feasible.

Impact of wettability on storage and recovery of hydrogen gas in the lesueur sandstone formation (Southwest hub project, Western Australia)

Geological storage has been proposed as a new technology to temporarily store significant amounts of hydrogen (H2) gas in depleted gas reservoirs, underground salt caverns, or saline aquifers. Often, such subsurface reservoirs naturally contain trace amounts of organic acids, and these compounds can considerably alter the wettability of reservoir rocks, causing them to become less water-wet. We carried out Molecular Dynamics (MD) simulations of contact angles in a quartz-brine-H2 system to evaluate wettability in realistic subsurface situations. MD simulations suggest that Humic acid makes quartz more hydrophobic, which can affect the overall behaviour of the storage reservoir. For the first time, this effect was experimentally investigated for a natural sandstone reservoir from the South West Hub Project, i.e., the Lesueur Sandstone (LS) formation. Multi-stage core flooding experiments were conducted on the same LS plug to investigate the impact of wettability alteration on initial and residual hydrogen saturation/trapping at depth. First, consecutive brine-H2 drainage-imbibition cycles were carried out on the natural sample; the result indicated that the rock-brine-H2 system was essentially water-wet. Then, the sample was aged in Humic acid with a molarity of 10−2 M for 42 days at 5 °C and 0.1 MPa. The wettability of the storage system shifted toward a less water-wet state, i.e., more hydrophobic. As a result of Humic acid ageing, the initial hydrogen saturation reduced from 29% to 15%, and the residual hydrogen trapping reduced from 23% to 11%. This is attributed to a change induced in the capillary force (i.e., snap-off) controlled by wettability and pore size. In addition, the wettability change induced by Humic acid increased the hydrogen recovery rate from 20.7% to 26.7%.

Investigation of the Selectivity of the Water Shutoff Technology

High water-cut oil production is one of the major issues in the petroleum industry. The present study investigates different profile control solutions, with an emphasis on selective methods and materials that mostly decrease the permeability of water-saturated reservoir areas. To achieve the selective water flow blockage in fractured porous media, the sodium silicate-based gel-forming composition was developed. The test procedure was created to assess selective and strength characteristics of the presented composition. According to the results of this procedure, adding polyatomic alcohols to the mentioned composition enhances its hydrophilic behavior in water-saturated rocks (work of adhesion increases from 117 to 129 mJ/m2) and reduces the hydrophobic behavior in oil-saturated rocks (work of adhesion drops from 110.3 to 77.4 mJ/m2). The selectivity of the composition performance is validated by its higher wettability of water-saturated reservoir rocks compared with oil-saturated; thus, the composition creates a more stable water shutoff barrier when entering the water zone in a formation. As a result of core flooding experiments in natural, fractured, porous core samples, the efficiency of the water blocking capacity of the composition was proved. In addition, these tests showed the selectivity of the composition because the permeability decrease in water-saturated core samples was higher than in oil-saturated ones. The experimental value of the selectivity coefficient was 152.14.

Experimental evaluation of sandstone stimulation fluids for acid sludge prevention during oilwell matrix stimulation jobs

Acid induced sludge can compromise matrix stimulation jobs performance in oil well interventions, it is associated to multiple sources including combinations of iron dissolved components, acid type and strength, certain crude oils and different type of additives such us surfactants, acid corrosion inhibitors, etc. Along with it generally comes changes in reservoir rock wettability and poor emulsion break which ends in emulsion blockage and that seriously compromises reservoir fluids recovery. The purpose of this study is the implementation of compatibility tests in different acid & crude oil proportions to find the appropriate additives and its concentrations to control acid induced sludge, shorten emulsion breaking times and avoid wettability changes. Two stimulation fluids at different acid strengths were successfully adjusted to prevent sludging tendencies finding ferric iron inhibitors, anti-sludge agents, mutual solvents, and surfactants as critical materials to prevent and control sludge formation prior to job executions

Experimental Core Flooding Investigation of New ZnO-γAl2O3 Nanocomposites for Enhanced Oil Recovery in Carbonate Reservoirs.

Generally, crude oil production in mature oil reservoirs is difficult. In this regard, some nanoparticles have been used to upgrade injected water into oil reservoirs. These nanoparticles can be used in a variety of injectable waters, including smart water (SMW) with special salinity. This study aims to evaluate the performance of the injection of SMW with ZnO-γAl2O3 nanoparticles in enhanced oil recovery (EOR). The performance of SMW with ZnO-γAl2O3 nanoparticles in regard to contact angle (CA), interfacial tension (IFT) reduction, and oil production with core flooding tests was investigated. The newly prepared ZnO-γAl2O3 structure was characterized by energy dispersive X-ray (EDX), Fourier transform infrared (FT-IR) spectroscopy, transmission electron microscopy (TEM), scanning electron microscopy (SEM), and X-ray diffraction (XRD) analyses in this research. The effects of different concentrations of nanofluids on zeta potential (ZP) and conductivity were investigated. The ZP test confirmed the results of the stability tests of the developed nanofluids in water-based solutions. After the introduction of ZnO-γAl2O3 nanoparticles into the formation of brine and SMW solutions, oil-water (O/W) IFT was reduced. Based on the results, the IFT decreased more when nanoparticles and ions were present in the system. The results of the present study showed that at the concentration of SW+300 ppm ZnO-γAl2O3, the IFT value reached 11 mN/m from 27.24 mN/m. The results of the CA tests showed that improving the capabilities of salt water in the presence of nanoparticles has resulted in a very effective reduction. Also, in this regard, very hydrophilic wettability was achieved using SMW with stable nanoparticles. Moreover, the results of the present study showed that at the concentration of SMW+300 ppm ZnO-γAl2O3 nanoparticles, the CA value reached 31 from 161°. In the end, the solution of SW+300 ppm ZnO-γAl2O3 improved the OR by 15 and 24%. This research indicated that it is possible to develop and implement different nanoparticles by combining SMW to manage reservoir rock wettability and maximize OR from carbonate reservoirs. Thus, this combination as an effective agent could significantly increase reservoir sweep efficiency. Thus, as a result, using the established hybrid technique has distinct advantages over using SMW flooding alone.

Insight into Nano-chemical Enhanced Oil Recovery from Carbonate Reservoirs Using Environmentally Friendly Nanomaterials.

The use of nanoparticles (NPs) in enhanced oil recovery (EOR) processes is very effective in reducing the interfacial tension (IFT) and surface tension (ST) and altering the wettability of reservoir rocks. The main purpose of this study was to use the newly synthesized nanocomposites (KCl/SiO2/Xanthan NCs) in EOR applications. Several analytical techniques including X-ray diffraction (XRD), Fourier transform infrared spectroscopy (FTIR), and scanning electron microscope (SEM) were applied to confirm the validity of the synthesized NCs. From the synthesized NCs, nanofluids were prepared at different concentrations of 100–2000 ppm and characterized using electrical conductivity, IFT, and ST measurements. From the obtained results, it can be observed that 1000 ppm is the optimal concentration of the synthesized NCs that had the best performance in EOR applications. The nanofluid with 1000 ppm KCl/SiO2/Xanthan NCs enabled reducing the IFT and ST from 33 and 70 to 29 and 40 mN/m, respectively. However, the contact angle was highly decreased under the influence of the same nanofluid to 41° and the oil recovery improved by an extra 17.05% OOIP. To sum up, KCl/SiO2/Xanthan NCs proved highly effective in altering the wettability of rocks from oil-wet to water-wet and increasing the cumulative oil production.

Experimental Investigation of Reservoir Rock Wettability Alteration by Matricaria Chamomilla Extract

Residual oil can be mobilized by reducing the interfacial tension between oil and water and/or by altering the wettability of the rock through surfactant flooding. Recently natural surfactants have been considered as opposite to synthetic surfactants due to environmental problems associated with synthetic surfactants. This work introduces a plant-based natural surfactant named Matricaria Chamomilla as an agent of reservoir rock wettability alteration. Qualitative and quantitative methods were used to measure rock samples' wettability. For this purpose, flotation wettability, separation wettability, and the pendant drop method were used. The results show that Matricaria Chamomilla extract (MCE) changes the reservoir rock wettability to some degree equivalent to other natural surfactants. The highest wettability variation was observed at 12%wt MCE concentration with 28% change and 21% for critical micelle concentration (CMC) of 5.5%wt.

Molecular dynamics simulation for quantitative characterization of wettability transition on silica surface

Surfactant controlling the wettability of reservoir rocks is one of the important ways to enhance oil recovery in low-permeability tight reservoirs. A large number of scholars have developed a series of excellent wettability control reagents through macro physical simulation experiments, but macro experiments are difficult to analyze the micro mechanism of liquid/liquid and liquid/solid interface action of reagents controlling rock wettability. In this paper, the wetting behavior of water molecules on silica surfaces modified with different hydroxylation, methylation and hydrophobic chain length was studied by molecular dynamics simulation, and the quantitative relationship between different modification degrees and wetting angle was established. The results show that the original wetting angle of silica is 58.5°, and the surface wettability can be changed from hydrophilic to hydrophobic through surface modification, with a wetting angle of 27.25°∼115.78°. With the increase of the coverage of hydrophobic methyl or hydrophilic hydroxyl modified groups, the wetting angle increases or decreases respectively. The quantitative relationship between modification degree and wetting angle was established by simulated data. With the increasing of the chain length of methyl group, the distance between water molecule and silica surface increases and the interaction decreases, which can improve the regulation effect of methyl group hydrophobicity. This paper provides a reference basis for the synthesis of rock wettability control reagent and the quantitative characterization of modification degree.

Effect of Native Reservoir State and Oilfield Operations on Clay Mineral Surface Chemistry.

An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid–solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10–13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals; however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery.

Investigation for CO2 Adsorption and Wettability of Reservoir Rocks

CO2 adsorption under pressure and temperature conditions for geological storage of CO2 is evaluated for two non-shale reservoirs in Canada. One is the Weyburn carbonate reservoir, where the world’s largest CO2 storage project is carrying on, and the other is a tight sandstone reservoir. Wettability of reservoir rock under high-pressure CO2 is also evaluated. Rocks from both reservoirs show a significant mass increase as a result of CO2 adsorption but distinctly different behaviors. A method for estimating the density of the adsorbed CO2 phase from gravimetric adsorption data is developed, and the result is in fair agreement with the expectation from analogy of adsorption with liquid condensation. A formula is proposed to predict CO2 storage capacity of reservoir rocks based on directly measured adsorption data. It is shown that CO2 adsorption could substantially increase the storage capacity and decrease leaking potential by decreasing overpressure to the reservoir caprock. Nearly 30 and 40% more CO2 could be stored by adsorption in the carbonate and tight sandstone rocks, respectively. Rock wettability reflected by the water contact angle suggests that CO2 could enter small rock pores to increase adsorption and utilization of reservoir capacity. The results can contribute to the evaluation of the impact of adsorption on CO2 storage.