Impact of Asphaltene Precipitation and Deposition on Wettability and Permeability

Impact of various aggregation kinetics on thermophoretic velocity of asphaltene deposition

Asphaltene deposition may pose serious challenges to flow assurance of crude oil in well columns. Different aggregation kinetics would partly be responsible for asphaltene particle growth ending in deposition on the surface of well columns. This work primarily investigates the thermophoretic deposition velocity caused by temperature gradients inside well columns for various asphaltene aggregation kinetics, including crossover behaviour, sedimentation, reaction-limited aggregation (RLA), and diffusion-limited aggregation (DLA). To do so, the experimental observations of size distribution for a live crude oil was performed at 80 °C and pressure range of 4500-5500 psia. Moreover, various patterns of different size distributions were gathered from the literature for the sake of comparison. Next, a well column in southern Iran was selected to study the kinetic behaviour of thermophoretic velocity of deposition, with a difference between geothermal and static temperatures of around 5 to 50 °C. The non-isothermal deposition velocity was shown to decrease from the top to the bottom of the well column, according to the findings of the study. The results also revealed that the thermophoretic velocity decreases as particle size increases and vice versa. This was confirmed by examining a comparably large range of asphaltene particle sizes, ranging from approximately 100 nm to roughly 9 µm. Practical implications of these findings were also discussed which would provide guidance for mitigation of asphaltene deposition in well columns.

Mechanistic understanding of asphaltene precipitation and oil recovery enhancement using SiO2 and CaCO3 nano-inhibitors

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid-base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors.

Density functional theory investigation of the contributions of π-π stacking and hydrogen bonding with water to the supramolecular aggregation interactions of model asphaltene heterocyclic compounds

CONTEXT

A complex supramolecular process involving electrostatic and dispersion interactions and asphaltene aggregation is associated with detrimental petroleum deposition and scaling that pose challenges to petroleum recovery, transportation, and upgrading. The homodimers of seven heterocyclic model compounds, representative of moieties commonly found in asphaltene structures, were studied: pyridine, thiophene, furan, isoquinoline, pyrazine, thiazole, and 1,3-oxazole. The contributions of hydrogen bonding involving water bridges spanning between dimers and π-π stacking to the total interaction energy were calculated and analyzed. The distance between the planes of the aromatic rings is correlated with the π-π stacking interaction strength. All the dimerization reactions were exothermic, although not spontaneous. This was mostly modulated by the strength of the hydrogen bond of the water bridge and the π-π stacking interaction. Dimers bridged by two water molecules were more stable than those with additional water molecules or without any water molecule in the bridge. Energy decomposition analysis showed that the electrostatic and polarization components were the main stabilizing terms for the hydrogen bond interaction in the bridge, contributing at least 80% of the interaction energy in all dimers. The non-covalent interaction analysis confirmed the molecular sites that had the strongest (hydrogen bond) and weak (π-π stacking) attractive interactions. They were concentrated in the water bridge and in the plane between the aromatic rings, respectively.

METHODS

The density functional ωB97X-D with a dispersion correction and the Def2-SVP basis set were employed to investigate supramolecular aggregates incorporating heterocycles dimers with 0, 1, 2, and 3 water molecules forming a stabilizing bridge connecting the monomers. The non-covalent interactions were analyzed using the NCIplot software and plotted as isosurface maps using Visual Molecular Dynamics.

The Neglected Role of Asphaltene in the Synthesis of Mesophase Pitch

This study investigates the synthesis of mesophase pitch using low-cost fluid catalytic cracking (FCC) slurry and waste fluid asphaltene (WFA) as raw materials through the co-carbonization method. The resulting mesophase pitch product and its formation mechanism were thoroughly analyzed. Various characterization techniques, including polarizing microscopy, softening point measurement, Fourier-transform infrared spectroscopy (FTIR), and thermogravimetric analysis (TGA), were employed to characterize and analyze the properties and structure of the mesophase pitch. The experimental results demonstrate that the optimal optical texture of the mesophase product is achieved under specific reaction conditions, including a temperature of 420 °C, pressure of 1 MPa, reaction time of 6 h, and the addition of 2% asphaltene. It was observed that a small amount of asphaltene contributes to the formation of mesophase pitch spheres, facilitating the development of the mesophase. However, excessive content of asphaltene may cover the surface of the mesophase spheres, impeding the contact between them and consequently compromising the optical texture of the mesophase pitch product. Furthermore, the inclusion of asphaltene promotes polymerization reactions in the system, leading to an increase in the average molecular weight of the mesophase pitch. Notably, when the amount of asphaltene added is 2%, the mesophase pitch demonstrates the lowest ID/IG value, indicating superior molecular orientation and larger graphite-like microcrystals. Additionally, researchers found that at this asphaltene concentration, the mesophase pitch exhibits the highest degree of order, as evidenced by the maximum diffraction angle (2θ) and stacking height (Lc) values, and the minimum d002 value. Moreover, the addition of asphaltene enhances the yield and aromaticity of the mesophase pitch and significantly improves the thermal stability of the resulting product.

Asphaltene Remediation and Improved Oil Recovery by Advanced Solvent Deasphalting Technology

Resin molecules play a crucial role in the stability of colloidal asphaltene particles in petroleum reservoirs. De-stabilization of the asphaltene/resin interaction due to changes in thermodynamic parameters can cause asphaltene precipitation, thus leading to petroleum field problems such as decreased in situ permeability, as well as severe plugging problems in production facilities. One remedial technology used in the oil industry involves developing synthetic resins with enhanced chemical potential to increase the stability of asphaltene in the oil phase. However, accurately predicting what synthetic resin structures are compatible with asphaltenes in this context can be difficult and ineffective. Here, we introduce a method that enhances the stability of colloidal asphaltene in petroleum fluid by increasing the concentrations of natural-state oil resins and increases reservoir oil recovery by increasing the oil's aromatic power solvency. The stability of colloidal asphaltene and improvements in oil reservoir recovery were investigated by using an oil prefractionation process and a solvent deasphalting technology based on the residuum oil supercritical extraction process to develop three types of deasphalted oils derived from Kuwait Marrat oil. Using these methods, we found that resin concentration by volume in Marrat oil increased with the removal of more oil fractions. Asphaltene stability in the oil phase was strongly influenced by resin concentration. The deasphalted oils' aromatic power solvency increased the oil reservoir permeability by twofold. No formation damage was observed for all DAO products in core flooding tests.

Screening and Investigation on Inhibition of Sediment Formation in a Kuwait Light Crude Oil by Commercial Additives with Some Guidelines for Field Applications

The precipitation of asphaltene and waxes occurs when crude oil characteristics change as a consequence of pressure, temperature variations, and/or chemical modifications, etc. The costs associated with the cleaning of deposition on the production equipment and the loss of profit opportunities can go beyond hundreds of millions of USD. Thus, there is a strong incentive to search for ways to mitigate deposit formation during the crude production process. A light crude bottom hole fluid sample from a deep well with an asphaltene deposition problem was analyzed in the laboratory. Basic data on density, viscosity, bubble point, GOR, and asphaltene onset pressure were measured at a PVT laboratory. Asphaltene characterization, as a prescreening for appropriate inhibitors, has been conducted using asphaltene phase diagrams (APD). The APD generated from two developed software programs in both Matlab and Excel codes were favorably compared with the phase behavior of other oil samples available in the literature and has shown to be an excellent match. Various test methods were used to demonstrate the asphaltene instability of the oil samples. Eleven chemical inhibitors from five global companies were screened for testing to inhibit the precipitation. The optimum concentration and the amount of reduction in precipitation were determined for all of these chemicals to identify the most suitable chemicals. Finally, some recommendations are given for the field application of chemicals.

Low-Temperature Oxidation of Heavy Oil Asphaltene with and without Catalyst

In this study, the asphaltene extracted from Luntai heavy oil was oxidized by a mixture of propionic anhydride and hydrogen peroxide without and with a catalyst. Elemental analysis and infrared spectroscopy results indicated the occurrence of oxygen addition, condensation, and side chain cleavage reactions in the oxidation process. Oxidation products were divided into methanol solubles and methanol insolubles. The H/C and O/C atomic ratios of the MeOHS in the oxidation products without a catalyst were higher than those of the Luntai asphaltene. MeOHS had fewer aromatic rings than Luntai asphaltene. Compared with the oxidative reaction without a catalyst, the total mass of oxidation products and the proportion of MeOHS in oxidation products both increased after catalytic oxidation. This low-temperature oxidation technology can be used to upgrade asphaltenes, and thus can promote the exploitation and processing of heavy oil.

Asphaltene Precipitation Prediction during Bitumen Recovery: Experimental Approach versus Population Balance and Connectionist Models

Deasphalting bitumen using paraffinic solvent injection is a commonly used technique to reduce both its viscosity and density and ease its flow through pipelines. Common modeling approaches for asphaltene precipitation prediction such as population balance model (PBM) contains complex mathematical relation and require conducting precise experiments to define initial and boundary conditions. Machine learning (ML) approach is considered as a robust, fast, and reliable alternative modeling approach. The main objective of this research work was to model the effect of paraffinic solvent injection on the amount of asphaltene precipitation using ML and PBM approaches. Five hundred and ninety (590) experimental data were collected from the literature for model development. The gathered data was processed using box plot, data scaling, and data splitting. Data pre-processing led to the use of 517 data points for modeling. Then, multilayer perceptron, random forest, decision tree, support vector machine, committee machine intelligent system optimized by annealing, and random search techniques were used for modeling. Precipitant molecular weight, injection rate, API gravity, pressure, C₅ asphaltene content, and temperature were determined as the most relevant features for the process. Although the results of the PBM model are precise, the AI/ML model (CMIS) is the preferred model due to its robustness, reliability, and relative accuracy. The committee machine intelligent system is the superior model among the developed smart models with an RMSE of 1.7% for the testing dataset and prediction of asphaltene precipitation during bitumen recovery.

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

Application of the UNIFAC Model for the Low-Sulfur Residue Marine Fuel Asphaltenes Solubility Calculation

Since 2020, 0.5% limits on the sulfur content of marine fuels have been in effect worldwide. One way to achieve this value is to mix the residual sulfur and distillate low sulfur components. The main problem with this method is the possibility of sedimentation instability of the compounded residual marine fuel due to sedimentation of asphaltenes. In this paper, the application of the UNIFAC group solution model for calculating the solubility of asphaltenes in hydrocarbons is considered. This model makes it possible to represent organic compounds as a set of functional groups (ACH, AC, CH2, CH3), the qualitative and quantitative composition of which determines the thermodynamic properties of the solution. According to the asphaltene composition, average molecular weight (450–2500 mol/L) and group theories of solutions, a method for predicting the sedimentation stability of compounded residual marine fuels was proposed. The effect of the heat of fusion, temperature of fusion, molecular weight, and group composition on the solubility of asphaltenes in marine fuel has been evaluated. The comparison of the model approach with the data obtained experimentally is carried out. The results obtained make it possible to predict the sedimentation stability of the fuel system depending on the structure and composition of asphaltenes.

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.

A Surface Charge Approach to Investigating the Influence of Oil Contacting Clay Minerals on Wettability Alteration

Reservoir rock wettability has been linked to the adsorption of crude fractions on the rock, with much attention often paid to the bulk mineralogy rather than contacting minerals. Crude oil is contacted by different minerals that contribute to rock wettability. The clay mineral effect on wettability alterations is examined using the mineral surface charge. Also, the pH change effect due to well operations was investigated. Clay mineral surface charge was examined using zeta potential computed from the particle electrophoretic mobility. Clay minerals considered in this study include kaolinite, montmorillonite, illite, and chlorite. Results reveal that the clay mineral charge development is controlled by adsorption of ionic species and double layer collapse. Also, clay mineral surface charge considered in this study shows that their surfaces become more conducive for the adsorption of hydrocarbon components due to the presence of salts. The salt effect is greater in the following order: NaHCO₃ < Na₂SO₄ < NaCl < MgCl₂ < CaCl₂. Furthermore, different well operations induce pH environments that change the clay mineral surface charge. This change results in adsorption prone surfaces and with reservoir rock made up of different minerals, and the effect of contacting minerals is critical as shown in our findings. This is due to the contacting mineral control wettability rather than the bulk mineralogy.