Low Asphaltene Research Articles

Stabilization mechanism of emulsion gels of crude oil with low asphaltene, resin, and wax contents

Stabilization mechanism of emulsion gels of crude oil with low asphaltene, resin, and wax contents

Evaporation and combustion of low asphaltene heavy oil droplets under conditions representative of practical applications

The evaporation and burning characteristics of isolated heavy fuel oil (HFO) droplets are experimentally studied at conditions representative of practical applications, producing novel, detailed results on the effect of oxygen concentration. Also, and for the first time for HFO, the temporal evolution of the flame stand-off ratio (based on CH* emission) and the cenosphere burning size are presented along with the droplet size histories. The effect of ambient oxygen concentration is first analyzed qualitatively, identifying different sub-stages. Later, a quantitative analysis is presented in terms of ignition delay time, micro-explosion regimes, shell swelling ratio, cenosphere size and several time metrics. The results show that, as ambient oxygen changes, the liquid and solid stages show marked differences not only in terms of time scales but also in the transitions of burning regimes. Cenospheres generated in oxygen-free conditions are found to be ∼1.4 times larger than those in droplet combustion. Although similar in size, the solid-to-liquid consumption time ratio in 5% O2 is found to be significantly longer, about twice than for the 10% O2 ambient. The characterization of these differences is thought to be relevant not only for oil flames but also for the promising future of heavy oil gasification applications.

Pilot-scale study of methane-assisted catalytic bitumen partial upgrading

The direct utilization of heavy and extra-heavy crude oils presents a formidable challenge due to their inherent physical and chemical properties such as high C/H ratio, extremely high viscosity and density, low APIo, super low mobility, high asphaltene and impurity (Fe, Ni, Co, S, N, etc.) contents. To tackle these problems cost-effectively, we have proposed and established a novel technique, distinct from conventional hydrotreating, for catalytic partial upgrading of extra heavy crudes with co-fed methane and a multi-functional catalyst. This technique has been further optimized using lab-scale batch reactors (100 mL, 300 mL), bench-scale and pilot-scale fixed bed reactors with their processing capacity of 250 mL/day and 20 L/day, respectively. The feasibility, stability, and profitability of this technique have been successfully verified using all these facilities and a wide variety of feedstock. Yet, further scale-up is necessary to advance this technique towards commercialization in industry. In this study, a pilot-scale prototype unit (processing capacity of 1 barrel/day) was designed and manufactured based upon the previous achievements, and a bitumen sample recovered from the Steam Assisted Gravity Drainage (SAGD) process was chosen as a typical extra heavy crude for the upgrading. A 30-day upgrading has been conducted smoothly without clogging and a liquid yield of 96.7 % was observed with remarkable enhancements in product quality. The notable decreases in density, viscosity, TAN, asphaltene content, and sulfur content were confirmed and consistent with previous results. A low olefin content implies excellent stability and compatibility of the liquid product. Additionally, a preliminary TEA (Techno-Economic Assessment) and LCA (Life-Cycle Analysis) have been conducted and the beneficial features of this novel technique have been confirmed with higher profitability, lower cost, and lower carbon footprint. This study further consolidates the advantages of this promising technique as a cost-effective and environmentally friendly alternative to hydrotreating for processing extra heavy crudes.

Synthesis of Modified Nano-Hydrotalcite Clay by Micellar Method and Its Application as Gel-like Crude Oil Flow Improver.

The network formed by wax precipitation at low temperature and colloid asphaltene at high temperature leads to poor fluidity of heavy oil, and the gelling characteristics of crude oil lead to pipeline blockage, which affects the exploitation, transportation and refining of crude oil. This work prepares a series of cationic surfactant-modified nano hydrotalcite (CSNH) to weaken the network structure and enhance the fluidity of the crude oil by the interaction of organic and inorganic functional groups on the CSNH surface and the components of the crude oil. The results show that CSNHs can all reduce the viscosity of crude oil from different oilfields, among which BTNH can reduce the viscosity of Yanglou (YL) crude oil by 98.8% (31 °C) and depress the pour point by 16.0 °C at most. In the investigation of the universality of crude oil, the modified hydrotalcite was applied to the mixed crude oil (CQH) of Changqing Oilfield, the crude oil (J76) of Jidong Oilfield, the high pour point oil (GN) of Huabei Oilfield, and the crude oil (HQ) of Tuha Oilfield. The viscosity reduction rates were 53.2%, 86.2%, 42.7%, and 63.8%, respectively. The characterization of this nano material confirms the modification of quaternary ammonium cationic surfactant on the surface, resulting in a smaller particle size, and the nano particles are stable under conventional conditions. The mechanism of viscosity and pour point reduction in crude oil by BTNH was discussed by DSC and optical microscopy analysis. The OH- and long-chain alkyl groups on the BTNH surface may interact with the resins, asphaltene and wax through hydrogen bonding and co-crystal, weakening or dispersing their aggregates, thereby improving the fluidity of crude oil. Finally, a cost evaluation was conducted on BTNH, providing useful support for subsequent promotion and application.

Carbon fibers from bitumen-derived asphaltenes: Strategies for optimizing melt spinnability and improving mechanical properties

The demand for low-cost carbon fibers with exceptional mechanical properties continues to grow across various industries. Bitumen-derived asphaltenes have emerged as a promising alternative to polyacrylonitrile (PAN), yet asphaltenes are a complex mixture of compounds, and the fundamental understanding of which asphaltenes are melt spinnable is not clearly understood. In this study, we utilized three distinct types of asphaltenes, each exhibiting notably distinct thermal softening temperatures (Ts) and aromaticity. The optimal melt processing conditions of asphaltenes were determined by dynamic rheology tests. Moreover, we introduced a novel strategy to facilitate the melt spinning of non-spinnable samples by preparing 100 % asphaltene blends with a low Ts asphaltene at different weight fractions. By this means, we achieved continuous melt spinning of precursor fibers. After careful selection of the stabilization and carbonization conditions, uniform carbon fibers were obtained from asphaltenes, which had the highest tensile strength (∼570 MPa) and modulus (∼60 GPa) values, comparable to isotropic pitch-based carbon fibers. Further post-processing of the as-spun fiber resulted in a significant increase in tensile properties, ∼1.1 GPa for strength and ∼91 GPa for modulus. Overall, this study identified spinnable asphaltene precursor characteristics and fiber post-processing methods for achieving low-cost, high-quality carbon fibers from asphaltenes.

Experimental and mechanism study of asphaltene on formation and stabilization of oil-based foam

Stable foam will be generated in the separation equipment after pressure reduction of crude oil, which reduce the separation efficiency and damage the power equipment. It is found that the foam formed by asphaltene-rich crude oil is particularly stable in oilfield production, and the action mechanism of asphaltene for foam remains unclear. Hence, a self-made foaming device was performed to investigate the foamability and foam stability of oil-based foam, and the impact of asphaltene concentration and oil phase composition on foam properties was elucidated from the interfacial properties, viscosity, foam structure and the microstructure of asphaltene. Results show that low asphaltene concentrations promote foaming and mitigate the foam destruction. In contrast, high asphaltene concentrations are detrimental to foaming and reduce foam stability. The changes in interfacial properties and viscosity caused by asphaltene are not the main factors affecting foam performance. Besides, we proposed that asphaltene present in the oil phase as non-adsorbed particle, and the foam stability is influenced by the shape, volume fraction and size distribution of the particles. Furthermore, the boundary conditions for the effect of asphaltene on foam performance are innovatively put forward. This work contributes to understand the mechanism by which the asphaltene enhances foam stability and provides theoretical support for defoaming techniques in crude oil foam.

Oil/Brine Screening for Improved Fluid/Fluid Interactions during Low-Salinity Water Flooding

Low-salinity water flooding/smart water flooding (LSWF/SWF) are used for enhanced oil recovery (EOR) because of the improved extraction efficiency. These methods are more environmentally friendly and in many scenarios more economical for oil recovery. They are proven to increase recovery factors (RFs) by between 6 and 20%, making LSWF/SWF technologies that should be further evaluated to replace conventional water flooding or other EOR methods. Fluid/fluid interaction improvements include interfacial tension (IFT) reduction, viscoelastic behavior (elastic properties modification), and microemulsion generation, which could complement the main mechanisms, such as wettability alteration. In this research, we evaluate the importance of fluid/fluid mechanisms during LSWF/SWF operations. Our study showed that a substantial decrease in IFT occurs when the oil asphaltene content is in the range of 0% to 3 wt.%. An IFT reduction was observed at low salinity (0–10,000 ppm) and a specific oil composition condition. Optimal IFT occurs at higher divalent ion concentrations when oil has low asphaltene content. For the oil with high asphaltene content, the sulfates concentration controls the IFT alteration. At high asphaltene concentrations, the formation of micro-dispersion is not effective to recover oil, and only a 5% recovery factor improvement was observed. The presence of asphaltene at the oil/low-salinity brine interface increases the energy required to disrupt it, inducing significant changes in the elastic moduli. In cases of low asphaltene content, the storage modulus demonstrates optimal performance at higher divalent concentrations. Conversely, at high asphaltene concentrations, the dominant factors to control the interface are paraffin content and temperature.

Pickering stabilization of water-in-crude oil emulsions by paraffin wax crystals: Insights from X-ray scattering

Previous studies suggest asphaltenes are active materials at the oil-water interface, affecting the formation and stability of crude oil emulsions. However, even oils of low asphaltene content generate stable emulsions, indicating the involvement of other oil fractions. Due to the role of paraffin waxes as Pickering stabilizers or gel network formers in emulsions from other applications, this study explores their stabilization capacity in water-in-oil (W/O) emulsions and their interaction with other fractions with interfacial activity. The extraction and physicochemical characterization of paraffin waxes from two Brazilian crude oils allowed us to correlate their properties with the emulsification of both crude and model oils. Removal of asphaltenes enhances emulsion stability. Emulsion preparation with crude oils without waxes and asphaltenes demonstrates the participation of other amphiphilic components in emulsion formation, whereas waxes are necessary for their stabilization. Experiments with emulsions formed by a model oil confirmed the combined action of waxes and an amphiphilic material in the formation and stabilization of the interfacial film. However, the combination of waxes and asphaltenes are ineffective. Small-angle X-ray scattering (SAXS) analysis revealed that waxes only form a lamellar structure when highly purified, suggesting Pickering stabilization rather than the formation of a gel network. In conclusion, polar oil fractions other than asphaltene play a crucial role in emulsion formation, whereas paraffin wax provides Pickering stabilization, even beyond the wax appearance temperature (WAT). This study enhances our understanding of the mechanisms governing waxy Brazilian crude oil emulsions.

Experimental study on the influence of asphaltenes with small dosage on the rheological and gelation behavior of waxy mixtures

Asphaltene, the heaviest and most polar non-hydrocarbon component in crude oil, may interact with waxes and affect the flow and gelation behavior of waxy oils. To further study the effect of asphaltene on the flow and gelation behavior of waxy oils, five wax-containing simulated oils with small dosage asphaltene content were prepared. Through pour point and rheometer test, it is found that asphaltenes can improve the low-temperature rheology of waxy oil. There is no critical turning point above which the low-temperature flowability improved. With an increase in asphaltene content from 0 wt% to 0.1 wt%, notable changes were observed in the properties of the waxy oil. The pour point, which measures the temperature at which the oil becomes too viscous to flow freely, exhibited a decrease from 25 ℃ to 13 ℃. Similarly, the gelation temperature, indicating the temperature at which the oil starts forming a gel-like consistency, also decreased from 29.0 ℃ to 27.1 ℃. These modifications can be attributed to the presence of asphaltene in the oil sample. This outcome can be attributed to the interference caused by the presence of asphaltenes, which disrupts the gel network structure of the waxy oil and consequently hinders its gelation process. Simultaneously, within the low asphaltene content range, an increase in asphaltene content resulted in a considerable decrease in the viscosity of the waxy oil at 10 °C, reducing it from 531.5 mPa s to 14 mPa s.

Interfacial materials and naphthenic acids from Brazilian crude oils: Colloidal characterization and water-in-oil emulsions

Different Brazilian crude oils form stable emulsions, although they have low asphaltenes content. The present study aimed to extract and characterize interfacial materials (IMs) from these oils to understand the factors driving this phenomenon. Polarized microscopy and small-angle X-ray scattering (SAXS) revealed that IMs can self-organize in certain conditions, and the formed aggregates could be related to the emulsification process. IMs promoted the formation of model emulsions of mineral oil and brine, but they were not enough to keep them stable. The original and residual oils from the extraction were also used to form emulsions with brine. SAXS, rheology, time-domain nuclear magnetic resonance (TD-NMR), and interfacial tension measurements allowed the comparison of these emulsions. Removal of IMs promoted self-organization of aggregates present in the oil, increasing the viscosity and stability of the emulsions. One of the crude oils had a significant content of naphthenic acids (NAs), which are known to behave as surfactants in some conditions. This fraction was also investigated, but it did not significantly affect the physicochemical properties of the emulsions in comparison with IMs. Hence, the aggregates formed by IMs combined with other components of the crude oils were probably responsible for the rheological properties affecting stability.

Study on the influence mechanism of asphaltenes on the gelation and flow behavior of wax-containing simulated oils

The precipitation of wax crystals will lead to the formation of gelation structures in waxy crude oils, and the presence of asphaltenes will affect the gelation and flow process of waxy crude oils. In this work, five waxy oils with different asphaltene contents were formulated, and the effect of asphaltene on the gelation and flow behavior of wax-containing simulated oils was investigated. The results show that asphaltenes can improve the low-temperature rheology of wax-containing simulated oils to a certain extent. When the asphaltene contents in wax-containing simulated oils increased from 0 wt% to 0.5 wt%, the pour points decreased from 25 °C to below 0 °C, while the gelation temperatures and storage modulus were also decreased from the initial 29.01 °C to 25.64 °C and 33262 Pa to 5.9 Pa, respectively. The results were due to the fact that the increase of asphaltene contents weakened the gelation network structure strength of wax-containing simulated oils and inhibited gelation process. Meanwhile, in the range of low asphaltene contents, the apparent viscosity of wax-containing simulated oils at 10 °C decreased from 531.5 mPa·s to 7.6 mPa·s with the increase of asphaltene contents.

Analysis of the Contribution of Petroleum Acid Components to the Viscosity of Heavy Oils with High TAN.

The viscosity of heavy oil hinders its cold production, posing a major challenge to its exploitation. The high viscosity of heavy oil can be attributed to the content of asphaltene. However, during the collection of heavy oil samples from various regions in China, we observed that heavy oils with high total acid number (TAN) but low asphaltene content also exhibit relatively high viscosity. Hence, the viscosity mechanism of high-acid crude oil, the influence of petroleum acid on heavy oil viscosity, should be investigated. In this study, Xinjiang Chunfeng heavy oil was selected for analysis, possessing a viscosity of 16,886 mPa·s at 50 °C and a high total acid number (TAN) of 17.72 mg KOH/g. Separation was performed on the deacidified oil and the acid component using an alkali-modified silica gel column. The viscosity changes of the deacidified oil and its blends with varying proportions of the acid component were determined, along with the viscosity changes of the deacidified oil and acid components in a toluene solution. The molecular composition was analyzed using a Fourier transform ion cyclotron resonance mass spectrometer (FT-ICR MS). The findings indicated successful separation of petroleum acid from the heavy oil, the acid component yield being 16.65 wt %. Furthermore, the viscosity of the petroleum acid was significantly higher than that of the deacidified oil. The rate of viscosity change of the acid component in the toluene solvent exceeded that of the deacidified oil, and the viscosity of the deacidified oil notably increased upon the addition of acid. In conjunction with the viscosity data, it was observed that the deacidified oil exhibited the removal of O2 and O4 compounds, resulting in a 43.11% viscosity reduction at 30 °C compared with crude oil. Thus, the monoacid and diacid components considerably affected the viscosity of heavy oil.

Destabilisation of water-in-crude oil emulsions using inorganic acids: The role of counter-ions and malonic acid

The quantitative role of pH with regards to the stabilisation of water-in-crude oil emulsions is not well established in literature. In this work, we report an observation wherein the prevention of stable emulsion formation occurs abruptly at a specific pH when water-in-crude oil emulsions are generated using inorganic acids (HCl, H2SO4 and HNO3) and crude oils with comparatively low asphaltene contents. Subsequent analysis of the aqueous phase indicated the emulsion prevention coincided with both increasing partitioning of metal cations and total organic content (TOC). Analysis of the TOC highlighted the presence of elevated concentrations of malonic acid and its derivatives which emphasises its importance in the demulsification process. The effect of elevated concentrations of malonic acid was investigated and determined to increase the rate of emulsion destabilisation when initially dissolved in the aqueous phase. Therefore, the role of malonic acid on emulsion stability is hypothesised to be due to its partitioning into the aqueous phase as a counter-ion to dissolved metals. These results highlight malonic acid as being a key chemical species to consider when assessing the stability of a water in crude oil emulsion.

Effect of kerosene aromaticity as a solvent on bulk and interfacial properties of Brazilian heavy crude oil with high asphaltene content

AbstractThis study investigated the effect of solvent aromaticity on asphaltene stability and interfacial behaviour using typical diluted heavy oils, which better represent the chemical diversity of petroleum components than previous studies that used simple solvent mixtures with low asphaltene concentrations. A Brazilian crude with high viscosity and asphaltene content was diluted with two kerosenes, one containing only saturated compounds (KeS), and the other a saturates/aromatics mixture (KeSA) to maintain total aromaticity in the oil mixture upon dilution. Viscosity, asphaltene stability, interfacial tension, and elasticity of the oil mixtures were measured, and correlated with emulsion stability, regarding the differences in solvent aromaticity and aromatics/saturates ratio. The results showed that the different kerosene compositions affected bulk viscosity and asphaltene flocculation, but had a lesser effect on oil/brine interfacial tension due to the high asphaltene content in the diluted oil. The elastic modulus decreased at higher dilutions with KeS, while it remained consistent for KeSA mixtures, which supported the differences obtained in emulsion stability, at solvent concentrations within the optimal aromaticity ratio reported for simple solvent mixtures. Interfacial segregation of the aromatics in KeSA was also observed, which has not been reported in previous studies using complex solvents. These findings suggest that the trends reported with model oils, such as heptol with added asphaltenes, can also be applied to more realistic complex oil mixtures with higher asphaltene concentrations. Nevertheless, it was suggested that maintaining the aromatic content may not be enough to prevent asphaltene flocculation upon dilution, due to the concurrent increase in saturates.

Integration of ramped temperature oxidation and combustion tube tests for kinetic modeling of heavy oil in-Situ combustion

In-situ combustion (ISC) has been applied as a follow-up process after steam injection-based technologies to improve heavy oil recovery and lower operating costs. Comprehensive understanding of the oxidation behavior and reliable prediction of the ISC performance are of great importance in the design of a ISC process. In this work, a calibration workflow was proposed to investigate the oxidation behavior and then establish a reaction kinetics model. A Ramped Temperature Oxidation (RTO) experiment was firstly conducted to capture the detailed oxidation behavior at elevated temperature conditions. Subsequently, a Combustion Tube (CT) test was performed to further evaluate the overall performance of ISC. Based on the integration of RTO and CT results, a comprehensive reaction kinetics model was developed to predict the ISC performance within a wide temperature range, including Low Temperature Oxidation (LTO), Negative Temperature Gradient Region (NTGR), and High Temperature Oxidation (HTO) reactions. It is found that the NGTR of heavy oil with high saturate and low asphaltene exhibits a narrow temperature range. The combustion front velocity in the RTO is comparable with that in the CT. In a stable HTO region, the CO2 concentrations in the RTO experiment and CT test were kept around 17% and 14%, respectively. The existence of LTO reactions in the RTO experiment caused the deviation of CO2 concentration. With the incorporation of the reaction model into simulation, a good agreement between measured and predicted results was obtained. This demonstrates that the established reaction model is capable of capturing the key oxidation mechanisms. In addition, the proposed workflow also helps upscale the oxidation behavior from a RTO experiment to a CT test and provide benchmarks for field operations.

Rapid and Simple Method for Measuring Petroleum Asphaltenes by the Centrifugation Technique.

Asphaltenes are heavy constituents of crude oil which affect the flow and viscosity of crude oil. They also stabilize water-in-oil emulsions which makes the separation process of water from oil during the primary treatment processes for crude oils more difficult and costly. Measuring asphaltenes has great importance, especially for crude oil production companies. Gravimetric and spectroscopic measurement methods are the basic techniques used by international references such as ASTM and IP. A new methodology has been introduced as a modification of ASTM D6560 gravimetric methodology by using the centrifugation technique in the separation of asphaltenes for different oil samples with the API gravity change from 17.4 (oil S1) to 39.8 (oil S5). The new methodology has the advantages of consuming little time, and multiple sample processing and can be done in the field and also in the lab. Moreover, it has good repeatability, reproducibility, and working range values compared to the reference gravimetric ASTM and IP methods. The repeatability of the new method was found to be 8.0% at its maximum value (S1, has a low asphaltene content), while the minimum value was found to be 3.75% (S10, has the highest asphaltene content). It was found that the maximum reproducibility value was 17.0% for the S1 sample and the minimum was 0.0% for S9 and S10 samples.

Characterization and Origin Analysis of Heavy Oil in the Western Sag of the Liaohe Basin.

This article systematically examines the physical characteristics, group composition characteristics, and geochemical characteristics of heavy oil in the Western Sag of the Liaohe Basin. The examination is based on the separation and quantitative analysis of crude oil and rock samples, as well as the analysis of test results from gas chromatography with saturated hydrocarbons and aromatic hydrocarbons. It also analyzes the generation mechanism and main controlling factors of heavy oil. The results show that heavy oil has low wax content (1.8–9.2%), a low freezing point (−19–38 °C), low sulfur content (0.28–0.5%), high colloid and asphaltene content, high density (0.926–1.008 g/cm3), and high viscosity (328–231910 mPa·s). The physical properties of the heavy oil in the same formation decrease from the depression’s edge toward its center and within the same area, and the physical properties in different formations also have an inverse relationship with burial depth. Biodegradation is the main reason for the formation of heavy oil. Based on the biodegradation degree, there are four types of heavy oil: undegraded, weakly degraded, moderately degraded, and severely degraded. The main controlling factors of biodegradation are temperature and the water environment. This study provides a method for studying the genetic mechanism of heavy oil, an approach for discovering similar genetic oil and gas, and a basis for the transformation of heavy oil field development.

Experimental investigation and thermodynamic modeling of asphaltene precipitation during pressure depletion and gas injection at HPHT conditions in live oil using PC-SAFT EoS

Due to the high costs associated with asphaltene precipitation and deposition, the study of this flow assurance problem has always been a major issue in the petroleum industry. We studied the asphaltene phase behavior in four Iranian live oil samples. First, asphaltene onset pressure and the amounts of the precipitated asphaltene during pressure depletion and gas injection at high-pressure high-temperature (HPHT) conditions were measured, experimentally. Then, thermodynamic modeling of asphaltene precipitation was performed using the perturbed chain form of the statistical associating fluid theory (PC-SAFT). In previous researches, PC-SAFT equation of state (EoS) along with the standard method of characterization was applied to light crude oil having low asphaltene content only, while in this work, three of the samples were heavy oil with high asphaltene content. To perform the thermodynamic modeling, the oil samples were characterized by two different methods. In the first method, the adjustable parameters of the model, which are the aromaticity of aromatics + resins and the aromaticity of asphaltene, were adjusted separately. In the second method, both of the parameters of the model were tuned simultaneously, as one of the novelties of this research. Then the amounts of precipitated asphaltene were modeled using the aforementioned characterization methods, and the results were compared to the experimental data. According to the results, simultaneous adjustment of the model parameters in the heavy oil samples could improve the average absolute deviation (AAD) by 5% - 12%. However, no remarkable improvement was observed for the light oil sample. For two of the oil samples, the proposed model showed a good agreement with the experimental data as the calculated AAD were 14% and 26%. For the other oil samples, the trend of the experimental data was predicted by the model, but the values of the experimental data could not be matched. We were able to solve this problem by introducing a confidence factor for experimentally measured data. By considering this weight factor, in one of the samples, the AAD was reduced by about 70% and reached 24%, and in other oil sample, the error decreased by 90% and reached 31%.

Study on the association driving force of low temperature coal tar asphaltenes

The aggregation of petroleum asphaltenes has been studied for decades by numerous experimental techniques, however, few studies had been performed on the special supramolecular structure of coal tar asphaltenes. In this paper, the methylation, alkylation experiments and molecular dynamics simulation were used to study the π-π interaction and hydrogen bond between coal tar asphaltenes. The results showed that the inter aromatic layer distance (Me) of asphaltenes, methylated and alkylated asphaltenes were 3.74, 2.12 and 1.73 respectively, and the average number of aromatic sheets (dm) was increased compared with asphaltenes. Asphaltenes existed in the form of aggregates in the toluene, as the concentration increased, the particle size also increased significantly, moreover, the particle size and the Me of alkylated asphaltenes are significantly less than asphaltenes, indicating that the π-π interaction was the main driving force for asphaltene association. Meanwhile, molecular simulation results showed the π-π interaction energy of asphaltenes dimers was -165.269 kcal·mol−1, which was much larger than the hydrogen bond energy -5.807 kcal·mol−1. In addition, the asphaltenes dimer layer spacing in quinoline, toluene and ethanol were 3.836 Å, 2.57 Å, and 4.783 Å respectively, which were all larger than the interlayer spacing of asphaltenes dimer 1.99 Å, and the asphaltenes dimer had a better disaggregates effect in quinolone.

New Nuclear Magnetic Resonance Approaches on the Evolution of Wax Mobility during Wax Crystallization

Wax crystallization at low temperature is one of the main problems affecting flow assurance during oil production. Wax inhibitors, such as pour point depressants (PPDs), and crude oil components, such as asphaltenes, are estimated to impact wax precipitation by both cocrystallization and the formation of complexes with waxes. However, the exact mechanism behind these interactions is not fully understood. Low field nuclear magnetic resonance (LF-NMR) methods have rarely been implemented for the analysis of wax precipitation in crude oil in spite of very promising results. This paper presents an improved method focused on the measurement of relaxation times which characterize the mobility of wax, asphaltene, and PPD molecules. As a wax crystal network forms at low temperature due to wax precipitation, dissolved wax molecules display a reduction in mobility as they become trapped in the pores and interact with the species of solids in the crystal network. The aim of this article is to analyze wax–wax and wax–inhibitor interactions by quantifying the amount of wax molecules trapped inside the crystal network. This paper focuses on investigating the effect of wax, asphaltene, and PPD concentrations on the percentage of precipitated wax with temperature and on the intensity of the reduced mobility wax region. The novelties of this work include the identification and quantification of a low mobility asphaltene nanoaggregate region, which may be used in future studies to characterize the changes in asphaltene aggregation state over selected concentration ranges. Additionally, the new NMR method allows us to understand and quantify with high resolution how asphaltenes in evolving aggregation states or other inhibitors impact the mobility of the dissolved wax within the wax crystal network. The new methods and breakthroughs about the wax precipitation mechanism may be correlated and extended in future studies to observations in real crude oil systems.