High Asphaltene Content Research Articles

Performance Evaluation of Demulsifier Using the Optimum Formulation HLD Concept: A Practical Case Using Heavy Crude Oil Diluted in Naphtha or in Synthetic Aromatic Oil

Summary Asphaltene-stabilized water-in-oil (W/O) emulsions can cause severe problems during oil production and transportation. These emulsions are broken by adding a demulsifying agent at a suitable concentration (CD*) to obtain the optimal formulation, with minimal emulsion stability (stability*). Herein, we studied, from a phenomenological point of view, the performance of two demulsifiers on W/O emulsion breaking with high asphaltene content. A very simple polyethoxylated nonylphenol demulsifier (6EO) and a complex commercial demulsifier (COD) were studied. The influence of the chemical nature of the oil phase on the performance of the demulsifiers was evaluated. The emulsion stability* and CD* values of W/O systems of heavy crude oil diluted in cyclohexane (Systems A and B) were compared to W/O emulsions composed by a heavy crude oil diluted in heavy naphtha or in an aromatic synthetic crude oil as the oil phase (Systems C and D). The results show that demulsifier performance improves significantly when the crude oil is diluted in heavy naphtha and in aromatic synthetic crude oil, obtaining unstable W/O emulsions (rupture time of 10−2–10−1 minutes). In the latter cases, the CD* value is significantly lower and with a wide area of low emulsion stability compared to systems formulated with crude oil diluted in cyclohexane. The mechanisms that generate this type of behavior are discussed and strategies to increase performance and robustness analyzed.

An experimental study of the combination of smart water and silica nanoparticles to improve the recovery of asphaltenic oil from carbonate reservoirs

Within recent decades, smart water (SW) injection has become an attractive approach to improve oil recovery from conventional oil reservoirs. However, less attention has been devoted to the application of this method to asphaltenic oil reservoirs. This study aims to evaluate the performance of the injection of SW + silica nanoparticles (SNPs) in improving oil recovery from such reservoirs. To this end, an extended series of measurements were conducted, including of oil-water interfacial tension (IFT), wettability, emulsion formation/stability, and core flooding tests. After the introduction of SNPs to formation brine (FB) and SW solutions, oil-water IFT was reduced by 17.5% and 52.5% respectively compared to their corresponding initial values. In addition, the SW + SNP solution could improve the wettability of the rock surface compared to FB + SNPs. Interestingly, we found that, due to its high asphaltene content, the crude oil used forms sludge in contact with FB, which will impose serious operational problems and production costs associated with the system. However, we observe that the presence of SNPs restrains sludge formation by breaking down asphaltene molecules as well as destabilizing oil-water emulsions. This is demonstrated by several centrifuge tests conducted to evaluate emulsion stability in the presence of FB + SNP and SW + SNP solutions. SARA analyses were also performed on the oil produced from core plugs after the injection of SW and SW + SNPs to better understand the role of SNPs in the deposition of complex structures like asphaltenes and resins groups in crude oil. • The performance of smart water + silica nanoparticles in IFT reduction and wettability alteration. • Crude oil-water emulsion stability in the presence of silica nanoparticles. • Application of SARA analyses to study asphaltene precipitation during core flooding tests. • Micrograph studies for emulsion stability in the presence of various aqueous solutions.

Asphaltene Inhibition and Flow Improvement of Crude Oil with a High Content of Asphaltene and Wax by Polymers Bearing Ultra-Long Side Chain

A high content of asphaltene and wax in crude oil leads to difficulties in the recovery and transportation of crude oil due to the precipitation of asphaltenes and the deposition of waxes. Comb-like polymers were found to be capable of inhibiting the aggregation of asphaltenes and crystallization of waxes. In this work, comb-like bipolymers of α-olefins/ultra-long chain (C18, C22 and C28) alkyl acrylate were synthesized and characterized by FT-IR and 1H NMR spectra. The results show that, for a model oil containing asphaltene, the initial precipitation point (IPP) of asphaltene was prolonged by UV, and the asphaltene particle size was reduced after adding the biopolymers, as revealed by dynamitic light scattering (DLS). The bipolymer containing the longer alkyl chain had a better asphaltene inhibition effect. However, DSC and rheological results show that the wax appearance temperature (WAT) of the typical high asphaltene and high wax content of crude oil was obviously reduced by adding bipolymers with shorter alkyl chains. The bipolymer (TDA2024-22) with a mediate alkyl chain (C22) reduced the viscosity and thixotropy of the crude oil by a much larger margin than others. Compared with the previously synthesized bipolymer with phenyl pendant (PDV-A-18), TDA2024-22 exhibited a better performance. Therefore, bipolymers with appropriate alkyl side chains can act as not only the asphaltene inhibitors but also wax inhibitors for high asphaltene and wax content of crude oil, which has great potential applications in the oil fields.

Understanding the behaviors of toluene in asphaltenes

During the aqueous-nonaqueous hybrid bitumen extraction (HBE) or the solvent extraction processes of unconventional oil ores, especially for the ores with high asphaltene content, solvent loss in tailings has been a major factor affecting environmental issues and operating costs. Herein, we proposed the experimental tests with molecular dynamic simulation methods to understand the cause and mechanism of solvent (e.g., toluene) loss together with asphaltenes. The experimental results by TG-MS clearly show that the asphaltenes can confine the toluene molecules (>0.19 wt%) in two different ways: i) a part of the toluene is adsorbed on the asphaltenes surface, and ii) a part of the toluene is trapped in asphaltenes ‘cage’, which could be released at much higher temperature (∼148–162℃, much higher than the boiling point of toluene). The relative amount of the confined toluene in the asphaltenes is also found to be asphaltene type-dependent. The asphaltenes with higher aromatic degree (i.e., Iran asphalt) showed stronger ability to entrain and confine toluene, leading to higher relative amount of solvent being occluded. To further understand how the asphaltenes confine the toluene molecules, the molecular dynamic simulation has been conducted. It is found that the van der Waals (vdW) forces between toluene and asphaltene are the major interactions which influence the escaping of toluene from asphaltene. The radial distribution function (RDF) analysis showed that the vdW force is mainly the π − π stacking between benzene ring in toluene and aromatic rings in asphaltenes. This finding would provide direct and fundamental understanding for the development of solvent recovery and viscosity reduction of heavy oils.

Simulation of catalytic upgrading in CAPRI, an add-on process to novel in-situ combustion, THAI

Based on the analysis of recent projections by the International Energy Agency (IEA), to meet the growing and subsequently declining demands of oil from now to 2040, we need up to around 770 billion barrels of oil. Since the worldwide total proved reserves of easy-and-cheaper-to-produce conventional oils is roughly only 520.2 billion barrels, the remaining 249.8 billion barrels must be obtained from unconventional petroleum resources (i.e. heavy oils and bitumen). These resources are however very difficult and costly to upgrade and produce due to their inherently high asphaltene contents which are reflected in their very high viscosities and large densities. However, still they should prove attractive development prospects if, as much as practicably possible, their upgrading can be performed in conjunction with in situ or downhole catalytic upgrading processes. Such projects will contribute significantly towards smoother and greener transition to full decarbonisation. Advanced technologies, such as the toe-to-heel air injection coupled to its add-on in situ catalytic process (i.e. THAI-CAPRI processes), have the potential to develop these reserves, but require further developmental understanding to realise their full capability. In this work, a new detailed procedure for numerically simulating the THAI-CAPRI processes is presented. The numerical model is made-up of Athabasca-type bitumen and it has a horizontal producer (HP) well that is surrounded by an annular layer of alumina-supported cobalt-oxide-molybdenum-oxide (CoMo/γ-Al2O3) catalyst. The simulation is performed using the computer modelling group (CMG) reservoir simulator, STARS. This new work has shown that the choice of the frequency factor of the catalytic reactions allowed model validation based on the degree of catalytic upgrading in form of API gravity. Overall, the work herein identifies the important parameters, such as API gravity, peak temperature, oil production rate, cumulative oil production, produced oxygen concentration, temperature distribution profile, extent of coke deposition on the catalyst surface, etc., governing the successful operation of the THAI-CAPRI processes. In particular, this study has shown that even in the vicinities of the mobile oil zone (MOZ) where the catalytic upgrading is expected to be taking place, the catalyst surfaces are covered with high concentration of coke. This finding is in parallel to the observations reported from experiment of CAPRI process alone. Therefore, it is concluded that when experimental studies of the THAI-CAPRI processes are to be conducted, a catalyst regeneration mechanism must be put in place in order to prolong the effectiveness and thus the life of the catalyst so that proper field operation design can be made. Additionally, the study has also shown that the temperature of the MOZ is less than 306 °C and that implies that an external source of heating the annular catalyst layer must be provided in order to effect the catalytic upgrading in the THAI-CAPRI processes. Thus, a new study should look at the feasibility of targeted heating (in the case of microwave) or conductive or resistive heating (in the case of electrical heating) to raise the temperature of the annular catalyst layer to that required to achieve the catalytic upgrading.

Visbreaking of heavy oil with high metal and asphaltene content

The visbreaking of Canadian oil sands bitumen (OSB) and Tahe atmospheric residue (AR) with high metal and asphaltene content was studied to deepen the understanding of the utilization of ultra-inferior heavy oil. The total content of nickel and vanadium in the asphaltenes contained in Canadian OSB reaches 1300 ppm, promoting large-scale aggregation of asphaltenes. Driven by high asphaltene content of 19.3 wt% and large-scale aggregation of asphaltenes, Canadian OSB with an initial boiling point (IBP) of 500 °C exhibits rapid condensation during visbreaking. Furthermore, those asphaltenes with the highest metal content participate in condensation first, producing metallic nickel in the formed coke. By changing cutting strategy, the group composition and metal distribution of Canadian OSB can be adjusted. A viscosity reduction rate above 99 % is obtained during the visbreaking of Canadian OSB with an IBP of 350 °C, similar to the visbreaking of Tahe AR with an asphaltene content of 15.4 wt% and a total metal content of 300 ppm.

NiO based catalysts obtained “in-situ” for heavy crude oil upgrading: effect of NiO precursor on the catalytic cracking products composition

Heavy and super-heavy oils are characterized by a high content of resins and asphaltenes, which complicate the transportation and refining of oil and lead to an increase in the cost of refinery products. Currently, of particular interest are catalysts that are formed directly under the conditions of the process from precursors, which are various salts. In this work influence of NiO precursor on the heavy oil catalytic cracking products composition. The upgrading in all experiments was carried out at a temperature 450 °C for 80 min. The optimal catalyst content calculated to the NiO in experiments 2 and 3 was 0.5 wt. % of the feedstock weight. The ratio salt:ethanol in experiment 3 was 1:1 wt. The products of catalytic cracking were analyzed by SARA, GC, XRD and FT-IR spectrometry. The dissolution of Ni(NO3)2•6H2O in ethanol results in a decrease in the content of high molecular weight components and an increase in the yield of the fraction boiling up to 360 °C. A decrease of sulfur content in the course of heavy oil cracking is caused by both interactions of NiO formed over cracking with S-containing compounds of feedstock leading to formation of Ni9S8 and Ni0.96S and sulfur removal in form of gas.

Relationship Between Tectonic Evolutions and Presence of Heavy Oil in The Central Sumatra Basin

Heavy oil is formed through biodegradation process of hydrocarbons, as well as water washing, in which light hydrocarbon fraction disappears and leaves the heavy fraction. Heavy oil is essentially an asphaltic, dense (low API gravity), and viscous that is chemically characterized by its high content of asphaltenes in the oil. Although variously defi ned, 25o API is set the upper limit for heavy oil. Heavy oil in the Central Sumatra Basin is evidently formed as a result of biodegradation and water washing (a hydrodynamic process within oil reservoir) mechanisms. These processes occur as result of tectonic uplift of the reservoir after it has been fi lled with hydrocarbons. Heavy oil reservoir depths in the Central Sumatra Basin are generally shallower than 1,000 feet (300-400 meters), at which surface water may may be associated with the reservoir hence enabling the heavy oil transformation. A combined geology, remote sensing/geographic information system ( GIS), geophysics, stratigraphy, and wellbased analyses is utilized to serve the study. It has been observed that within the northern part of the basin, heavy oil is mainly found in fi elds located within uphill fault blocks such as the up-thrown part of the Sebanga thrust fault with its Duri, Sebanga North, Kulin, Rantau Bais, Batang, Akar, and Genting fi elds. In the western part of the basin there are the Kumis, Kotalama and Pendalian heavy oil fi elds associated with Dalu-Dalu thrust fault and Gadang Island uplift. In total 51 fi elds/structures containing or suspected to contain heavy oil are associated with uplifted geological positions, hence showing the strong relations between tectonic evolutions and present day presence of heavy oil within the basin.

Effects of Molecular Structures of Poly(styrene-co-octadecyl maleimide) as a Flow Improver for the Model Crude Oil with a Relatively High Content of Asphaltenes

Poly(styrene-co-maleic anhydride)s (SMAs) with different compositions and molecular weight were synthesized through the reversible addition–fragmentation chain transfer polymerization technique. SMAs were converted to poly(styrene-co-octadecyl maleimide)s (SNODMIs) by amidation with octadecyl amine and subsequent imidization. SNODMIs with octadecyl branches were evaluated as flow improvers in the model crude oil with a high content of asphaltenes. The effects of molecular structures, including molecular weight, branch content, and imidization degree, on the effectiveness of SNODMI in reducing the viscosity and yield stress and improving the morphologies of asphaltene particles were thoroughly investigated using a rotational rheometer with parallel plate geometry and a polarizing microscope with a hot stage, respectively. It has been found that efficacy of SNODMI in reducing the viscosity and yield stress of the model crude oil increases with an increasing branch content of SNODMI. (alt)SNODMI with the highest branch content, approximately 45 mol %, achieved the best performance. Too high or too low molecular weight is not beneficial for SNODMI to improve the flow ability of the model crude oil. The appropriate molecular weight (Mₙ = 3500 Da) is required to achieve the optimal effectiveness. The optimal imidization degree of SNODMI is 100% and is independent of the branch content. The addition of SNODMI in a real crude oil has reduced the viscosity and yield stress by more than 90%.

A New Approach Utilizing Liquid Catalyst for Improving Heavy Oil Recovery

AbstractChemical-assisted enhanced oil recovery (EOR) has recently received a great deal of attention as a means of improving the efficiency of oil recovery processes. Producing heavy oil is technically difficult due to its high viscosity and high asphaltene content; therefore, novel recovery techniques are frequently tested and developed. This study contributes to general progress in this area by synthesizing an acidic Ni-Mo-based liquid catalyst (LC) and employing it to improve heavy oil recovery from sand-pack columns for the first time. To understand the mechanisms responsible for improved recovery, the effect of the LC on oil viscosity, density, interfacial tension (IFT), and saturates, aromatics, resin, and asphaltenes (SARA) were assessed. The results show that heavy oil treated with an acidic Ni-Mo-based LC has reduced viscosity and density and that the IFT of oil–water decreased by 7.69 mN/m, from 24.80 mN/m to 17.11 mN/m. These results are specific to the LC employed. The results also indicate that the presence of the LC partially upgrades the structure and group composition of the heavy oil, and sand-pack flooding results show that the LC increased the heavy oil recovery factor by 60.50% of the original oil in place (OOIP). Together, these findings demonstrate that acidic Ni-Mo-based LCs are an effective form of chemical-enhanced EOR and should be considered for wider testing and/or commercial use.

Interfacial Rheology Measured with a Spinning Drop Interfacial Rheometer: Particularities in More Realistic Surfactant–Oil–Water Systems Close to Optimum Formulation at HLDN = 0

AbstractThree different cases were selected to study the effect of physicochemical formulation on interfacial rheology properties of surfactant–oil–water (SOW) systems by increasing the complexity of the system from a basic case. This was performed by changing the normalized hydrophilic–lipophilic deviation (HLDN) to attain the optimum formulation at HLDN = 0. Two types of SOW systems were studied: the first one used an ionic surfactant with a salinity scan, and the second one a mixture of two nonionic surfactants in a formulation scan produced by changing their proportion. Both of them contained cyclohexane as a pure oil phase, without alcohol. Sec‐butanol was then added as a co‐surfactant with hardly any formulation influence on HLDN. The complexity in interfacial rheology was then increased by changing the oil to a light crude with low asphaltene content. The interfacial rheology is also reported for a realistic system with a high asphaltene content comprised of crude oil diluted in cyclohexane with a conventional surfactant and a commercial demulsifier. The findings confirm that at optimum formulation and whatever the scanning variable (salinity, average ethylene oxide number in the nonionic surfactant mixture, or surfactant/demulsifier concentration), the interfacial tension, and interfacial elastic moduli E, E′, and E″ exhibit a deep minimum. These observations are related to the acceleration of the surfactant exchanges between the interface, oil, and water, near the optimum formulation. Several arguments are put forward to explain how these findings could contribute to the decrease in emulsion stability at HLDN = 0.

Effect of Asphaltene on Threshold Pressure Gradient of Heavy Oil in Porous Media

Many studies have shown that heavy oil with high asphaltene content has a yield stress. Coupled with the solid-liquid interaction between porous media and heavy oil, there is a threshold pressure gradient when heavy oil flows in porous media. Meanwhile, some previous research has indicated that the high viscosity of heavy oil is the decisive factor for its threshold pressure gradient. Hence, this concept needs more clarification, especially because its accuracy is questionable. In this research, different oil samples with the same viscosity and also different asphaltene contents heavy oil samples were prepared. The viscosity of the different heavy oil samples was measured. Threshold pressure gradient experiments under different permeabilities and temperatures were also conducted on heavy oils. The results proved that the viscosity was not directly related to threshold pressure gradient of heavy oil. They also suggested that the heavy oil viscosity increased with the increase of asphaltene content. Moreover, the formula of the factors affecting threshold pressure gradient was regressed, and also its applicability was verified. As the temperature and core permeability increase, the threshold pressure gradient was also proven to decrease significantly. Furthermore, it was found that the threshold pressure gradient increased significantly with the increase of asphaltene content. Therefore, the heavy oil threshold pressure gradient could be characterized as a function of temperature, permeability, and asphaltene content. This study provided some theoretical support for the research attempts on the reduction of threshold pressure gradient and also on the effective development of heavy oil reservoirs.

Comprehensive analysis of multiple asphaltene fractions combining statistical analyses and novel visualization tools

Marine heavy fuel oils (HFOs), derived from and often blended with hydrotreated residual cuts, typically possess high boiling point, viscosity, and molecular complexity, and so are inherently challenging to analyze at the molecular level. Their high asphaltene content is associated with undesirable phenomena including flocculation, deposition, and black paint formation in marine engines. Asphaltene fractions of eight HFOs were selected for analysis by Fourier transform ion cyclotron resonance mass spectrometry (FTICR MS) due to their differing behaviour, including responsiveness to additive chemistries designed to stabilise against asphaltene handling issues. A selected mass region was isolated and fragmented using infra-red multiphoton dissociation (IRMPD), and the relative heteroatom content in asphaltene cores and smaller aromatic moieties, and degree of alkylation and aromaticity, of the fragments generated for each sample compared. A more extensive elucidation of the molecular-level differences between the n-alkane insoluble asphaltene fractions is afforded, with key components underlying variation in bulk behaviour identified through statistical approaches. The approach presented allows additive packages to be adjusted to address asphaltene handling issues presented by more challenging samples, and simpler and more ubiquitous formulations may eventually be developed.

Influence of asphaltene inhibitors on asphaltene deposition in the porous media

This article deals with organic asphaltene deposition in the reservoir rock, for crude oil having high asphaltene content and high apparent viscosity. The crude oil is characterized using thermal analysis through the thermogravimetric method. Crude oil is blended with heptane and flooded through the formation core at 55°C and 200-1200 psi pressure. With the rise in flow pressure, asphaltene precipitation became more significant with about four hundred times fall in the initial flow rate (flow rate at 200 psi) of crude oil at 1200 psi pressure. Phthalic acid and turpentine oil are used as asphaltene inhibitors for this crude oil. These asphaltene inhibitors are easy to procure, required less dosage for asphaltene dissolution and are relatively less toxic as compared to the other organic solvents used frequently as asphaltene inhibitor in oil industries. The asphaltene inhibitors are injected into the crude oil and flowed through the pores of the core. It is found that the crude oil treated with phthalic acid resulted in 88.23% increment its flow rate as compared to the turpentine oil, suggesting significant organic asphaltene dissolution in the formation rock.

Определение хлорорганических соединений в нефтях различного состава хроматографическим методом с использованием парофазного пробоотборного устройства

There are researches has been carried out on real objects (crude oils with a high content of paraffins, asphaltenes, naphthenes and resins) in order to determine the correctness and boundary conditions for the applicability of the gas chromatographic vapor-phase method for determining the concentration of organic chlorides in crude oil for performing in-line analysis. The application of this technique, regardless of the type and composition of crude oil, will make it possible to quickly determine the presence of organic chlorides in crude oil, which, in turn, prevents contaminated oil from entering pipelines and refineries.

Influence of the Chemical Composition of Asphalt and the 3D Morphology of the Aggregate on Contact Surface Adhesion

The influence of the chemical composition of asphalt, the aggregate lithology, and the morphological characteristics of the aggregate on the level of adhesion between the asphalt and the aggregate is investigated. A contactless three‐dimensional (3D) white‐light scanning technique is used to obtain point cloud data of the aggregate particles. Six independent feature parameters are used as evaluation indices to quantitatively describe the multilevel features of the 3D morphology of road aggregates. Methods for analyzing the feature parameters based on the point cloud data of the aggregate are presented. Subsequently, the process and evaluation standard of the adhesion test are improved to quantify the spalling degree of the asphalt film on the aggregate surface under boiling conditions. The influences of the chemical composition of the asphalt and the aggregate morphology on the level of adhesion between the asphalt and aggregate are analyzed, and the compatibility between aggregates with different lithologies and the asphalt is assessed. The results show that the shape factor (SF) can be used to characterize the needle‐flake shape of the particles, the ellipsoid index (E) is suitable to determine the angularity of the aggregate particles, and the 3D joint roughness coefficient (JRC3D) describes the roughness of the particle surface. The type of adhesion between the aggregate and the asphalt includes chemical and physical adsorption; chemical bonding is relatively strong, and the physical orientation force and mechanical interlocking force are relatively weak. Alkaline limestone aggregates should be used with asphalt with a high aggregate content of colloid and asphaltenes. Basalt aggregate with weak alkalinity should be used with asphalt with a high colloid content, and the use of angular aggregates should be avoided. Acidic aggregates with compact shapes, few edges and corners, and rough surfaces should be used prudently.

Efektywność środków chemicznych stosowanych w przesyle ropy naftowej z odwiertu do instalacji procesowych

Chemicals are added to crude oil to ensure that it flows from the well to the processing plant. Depending on the composition of the reservoir fluids being extracted (crude oil, reservoir water, natural gas), paraffin may be separated from the crude oil, hydrates may be formed from reservoir water and natural gas, and the combination of reservoir water and crude oil may form an emulsion. Those situations should be avoided to ensure continuous flow from the wellbore to the processing plant. To this end, chemicals, paraffin inhibitors, hydrate inhibitors, and demulsifiers are used. Based on the literature on the subject and on the author’s own experience from observing technological processes, research methods were proposed to assess the effectiveness of chemicals used to ensure the continuity of crude oil flow. The crude oil selected for the tests was characterised by a high content of paraffins, asphaltenes, chloride ions, and water. To determine the onset of paraffin precipitation, tests were conducted based on a change in viscosity and a coupon method – determining the weight gain on a coupon to check the effectiveness of a paraffin inhibitor. The rate of emulsion separation was evaluated in separating funnels. The water released from crude oil often leaches the salt contained within it. Various demulsifiers were used to investigate the separation of emulsions and the purification of oil from salts; silicone demulsifiers in particular were considered. To determine the change in the amount of salt in crude oil, a conductometric measurement was performed. The amount of demulsifier used for phase separation was determined by changing the surface tension. The proposed solution for the use of chemicals to transport and purify crude oil yields tangible economic benefits. The article summarises the research procedures and presents the results for selected crude oil and chemicals.

A Surfactant for Enhanced Heavy Oil Recovery in Carbonate Reservoirs in High-Salinity and High-Temperature Conditions

In view of the difficulty of producing heavy oil from carbonate reservoirs, the surfactant SDY-1 was synthesized by homogeneous solution polymerization with a homogeneous solution polymerization technique using aliphatic amine polyoxyethylene ether (PAEn) H(OCH2CH2)nNR(CH2CH2O)nH as the raw material, epichlorohydrin as the reaction intermediate, tetrabutylammonium bromide and pentamethyldivinyltriamine as the promoters, and alkylphenol as the catalyst. Based on the analysis of reservoir fluid and rock properties, the performance of the surfactant SDY-1 was evaluated in terms of its heat resistance, its salinity tolerance, its ability to change the heavy oil–water interfacial tension and rock wettability and its oil washing efficiency. The results show that when the salinity of the formation water is 2.23 × 105 mg/L, the addition of surfactant SDY-1 can lower the super-heavy oil–water interfacial tension with an asphaltene concentration of 30.19 wt.%, which is aged at a temperature of 140 °C for 3 days, from 22.41 to 0.366 mN/m. In addition, the surfactant SDY-1 can change the contact angle of super-heavy oil–water–rock from 129.7 to 67.4° and reduce the adhesion of crude oil to the rock surface by 99.26%. The oil displacement experiment indicates that the oil washing efficiency of the surfactant SDY-1 can reach 78.7% after ageing at a temperature of 140 °C for 3 days. Compared with petroleum sulfonate flooding, the addition of SDY-1 can improve the displacement efficiency by 33.6%, and the adsorption loss is only 0.651 mg/g oil sand. It has broad application prospects for heavy oil reservoirs with high temperatures, high pressures and high asphaltene contents.

Experimental characterization of viscoelastic behaviors, microstructure and thermal stability of CR/SBS modified asphalt with TOR

It is well known that crumb rubber (CR) and styrene–butadienestyrene (SBS) composite modified asphalt has better rheological and engineering performance. However, it always presents very poor compatibility and storage stability. Meanwhile, Trans-polyoctenamer (TOR) can effectively improve the compatibility and thermal stability of rubber asphalt. Thus, this study aims to investigate the effectiveness of TOR on rheological properties, microstructure and thermal stability of CR/SBS modified asphalt. The results show that TOR has a significant influence on strengthening anti-rutting and temperature sensitivity of CR/SBS modified asphalt. However, TOR has a slightly negative influence on the anti-cracking ability for CR/SBS modified asphalt, which still maintains the critical low temperature requirement. Furthermore, TOR could be able to promote the conformation of cross-linked structure between polymer and asphalt, resulting in a significant enhancement in rheological properties and thermal stability of CR/SBS modified asphalt. Lastly, the effects of TOR on viscoelastic performance for modified asphalt markedly depend on the component of neat asphalt, and high asphaltene content is beneficial for improving the rheological behavior effects of TOR.

Experimental studies on the effect of ultrasonic treatment and hydrogen donors on residual oil characteristics

Residual oil, the residue after the distillation of crude oil, imposes deleterious effects on refinery due to its high viscosity and asphaltene content. In this context, ultrasonic technology has been widely applied in refining processes given its high efficiency and minimal environmental impacts. To guide the selection of operation parameters, in this work, we probed the effect of treatment duration, power, and hydrogen donor on the characteristics of residual oil under ultrasonic treatments. Underlying mechanisms of ultrasonic treatments, in the absence and presence of hydrogen donors, were verified through systematically analyzing viscosity, component conversion, molecular weight, hydrogen distribution, and functional groups of residual oil. While viscosity reductions under low-power density treatment are caused by colloidal system disaggregation, high-power density treatment can bring in both chemical bond cleavage and colloidal system disaggregation. In addition, adding hydrogen donor can effectively prevent radical recombination, and thus increases the yield of saturate. These results provide fundamental understandings on the effects of ultrasonic treatments.