High Asphaltene Content Research Articles

Spatial distribution of remaining movable and non-movable oil fractions in a depleted Maastrichtian chalk reservoir, Danish North Sea: Implications for CO2 storage

Depleted oil and gas fields constitute potentially important storage sites for CO2 in the subsurface, but large-scale injection of supercritical (sc) CO2 in chalk has not yet been attempted. One of the risks is the adverse effect of the substantial amount of remaining oil in the chalk reservoirs on scCO2 injection. In order to counter an undesired effect on injectivity, a fundamental understanding of the spatial distribution and quantity of the movable, semi-movable, and non-movable oil, and solid bitumen/asphaltenes fractions of the remaining oil is critical. In this study a combination of organic geochemistry (gas chromatography of the saturated fraction and programmed pyrolysis), and reflected light microscopy was applied to evaluate and measure the spatial distribution, volume, and saturation of different oil fractions in a well-defined reservoir interval of a waterflooded Maastrichtian chalk reservoir in the Danish Central Graben, North Sea. A total of 127 samples from a slightly deviated vertical well and two ∼5 km-long horizontal wells from the Halfdan and Dan fields were analyzed. An original uneven distribution of oil saturation and composition or different production efficiency of different levels in the reservoir may account for variations in the total oil and oil fraction saturations. Gas chromatography shows that the solvent extractable oil is quite similar in composition, characterized by a dominance of polar compounds and a high content of asphaltenes. Extended slow heating (ESH) pyrolysis reveals that most of the remaining oil saturation consists of semi-movable oil and total non-movable oil (non-movable oil plus solid bitumen/asphaltenes). Reduced oil gravity values (API) are related to evaporation loss of the lightest hydrocarbon fraction during core storage and increase of the relative proportion of the heavier oil fractions by waterflooding during production. Microscopy disclosed three forms of oil: i) Patchy distributed lighter, movable oil showing a bluish fluorescence, ii) Brownish staining with a dark orange to brownish fluorescence, and iii) Dark brown non-fluorescing oil and black solid bitumen/asphaltenes occurring in microfossils and along deformation bands and stylolites, constituting the heavy non-movable oil fractions. There is a general correlation between bulk rock porosity and the total non-movable oil saturation. It thus appears that the heavy non-movable oil fractions preferentially occur in association with low-permeability heterogeneities within high-permeability stratigraphic intervals. These intervals appear to favor accumulation of non-movable oil and solid bitumen/asphaltenes and may carry a higher risk for impeding scCO2 flow.

Transforming Petrochemical Processes: Cutting-Edge Advances in Kaolin Catalyst Fabrication

The depletion of conventional light petroleum reserves has intensified the search for alternative sources, notably, low-quality heavy oils and byproducts from heavy crude processing, to meet the global demand for fuels, energy, and petrochemicals. Heavy crude oil (HO) and extra heavy crude oil (EHO) represent nearly 70% of the world’s reserves but require extensive upgrading to satisfy refining and petrochemical specifications. Their high asphaltene content results in elevated viscosity and reduced API gravity, posing significant challenges in extraction, transportation, and refining. Advanced catalytic approaches are crucial for efficient asphaltene removal and the conversion of heavy feedstocks into valuable light fractions. Kaolin, an aluminosilicate mineral, has emerged as a key precursor for zeolite synthesis and a promising catalyst in upgrading processes. This article provides a comprehensive exploration of kaolin’s geological origins, chemical properties, and structural characteristics, as well as the various modification techniques designed to improve its catalytic performance. Special focus is given to its application in the transformation of heavy crudes, particularly in facilitating asphaltene breakdown and enhancing light distillate yields. Finally, future research avenues and potential developments in kaolin-based catalysis are discussed, emphasizing its vital role in addressing the technological challenges linked to the growing reliance on heavier crude resources.

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.

Low rigidity despite high asphaltene content in bitumen: The role of resins

This research presents a laboratory study on three different bitumens, chosen as representative, coming from three different oils with different origins (Saudi Arabia, Venezuela, Russia) for assessing their structural differences due their different origins. The three bitumens have penetration indexes of 160/220, 70/100, 70/100 respectively, whereas their S.A.R.A. compositions showed marked differences particularly in the asphaltene and resin content, being the bitumen from Saudi Arabia particularly rich in such fractions, and that from Venezuela possessing the lower content of these. Rheological characterization carried out as a function of frequency and temperature suggests that: (i) the modulus at an angular frequency of 1 rad/s takes the lowest value for sample from Saudi Arabia, in accordance with the penetration index trend of the samples (ii) from a microscopic point of view, the average number of first neighbors involved in the flowing process is around one. Further analysis involved the extraction of the asphaltenic fraction according to the standard ASTM D4124 procedure: the melting point of the asphaltene fraction is 175 and 195 °C for the samples from Venezuela and Russia, respectively, while it can hardly be detected for the sample from Saudi Arabia. This anomalous behavior has been interpreted with the aid of X-Ray scattering data, which highlighted a lower order in asphaltene assembly at higher level of aggregation, which means that asphaltene molecules are arranged to form local assemblies with structural well-defined order only at short range, being higher levels of aggregations more disordered. All the data self-consistently show that the bitumen from Saudi Arabia, thanks to a higher content of resins, can stabilize more efficiently aphaltenes and therefore the latter can form ordered stacks only ad short range (only few Angstroms), leaving a more amorphous structure at longer ranges with consequently higher penetration index and lower modulus.

STUDY OF THE EFFECT OF SUPERCRITICAL WATER ON SOLID PRODUCTS OBTAINED AFTER CRACKING

One of the possible applications of supercritical water is the conversion of heavy hydrocarbon feedstocks with a high content of resins and asphaltenes. The use of supercritical water makes it possible to reduce the yield of solid products and increase the yield of light fractions. In this work, a comparative analysis of the cracking processes of petroleum residue, asphaltenes and resins isolated from it was carried out in an environment of supercritical water and without water. The experiments were carried out in an autoclave at a temperature of 450 °С and a pressure of up to 47 MPa. Cracking duration – 60 min. Cracking of petroleum residue, as well as its individual components - resins and asphaltenes, in a supercritical water environment - showed a positive effect on conversion; in all experiments, the yield of solid products decreased and the yield of maltenes increased. Solid products were studied using X-ray diffraction and thermogravimetric analysis and scanning electron microscopy. Using X-ray diffraction analysis, the influence of supercritical water on the parameters of the macrostructure was studied. It was determined that cracking with water affects the increase in the distance between saturated fragments of molecules (dr) in the structure of solid cracking products in comparison with products obtained without water. Using scanning electron microscopy, the surface of particles of insoluble cracking products was characterized. Solid products obtained in a supercritical water environment have a porous surface. According to thermal analysis data, it is shown that solid products obtained by cracking in water are characterized by more intense dynamics of sample weight loss and a smaller residue at the final temperature. For citation: Nalgieva Kh.V., Kopytov M.A. Study of the effect of supercritical water on solid products obtained after cracking. ChemChemTech [Izv. Vyssh. Uchebn. Zaved. Khim. Khim. Tekhnol.]. 2024. V. 67. N 8. P. 113-120. DOI: 10.6060/ivkkt.20246708.14t.

Intensyfikacja wydobycia i przygotowania ropy naftowej o wysokiej lepkości ze złoża Kokhanivka do produkcji bituminu

The existing problems of production, collection and preparation of high-viscosity oils need to be solved by further research and search for effective technologies. The oil of the Kokhanivske field is unique among the fields of Prykarpattia region, which is characterized by a high density of ≈1000 kg/m3, a significant content of asphaltenes, resins up to (45–60% by weight) and sulphur (7%), which is most suitable for the production of the highest quality bitumen. According to the physico-chemical characteristics and composition of the oil of the Kokhanivske field, an analysis of the conformity of this oil to the bituminous group according to the international classification was carried out. It is emphasized that this oil can be an analogue of the raw material from which high-quality bitumen of the Swedish company Nynas are produced. In connection with the above-mentioned physical and chemical properties of the oil from the Kokhanivske field (high density, viscosity asphaltene and resin content, etc.), significant complications arise during its collection and preparation. In order to solve the problem of preparing this type of oil, a technological solution for its preparation with a wave field of different intensity is proposed. In accordance with this technological solution, a laboratory setup was developed to study the effect of a wave field of different intensity on high-viscosity oil of the Kokhanivske field based on the Yutkin effect.

Inhibition of wax crystallization and asphaltene agglomeration by core-shell polymer@SiO2 hybride nano-particles

The gelation of crude oil with high wax and asphaltene content at low temperatures often results in the block of transportation pipeline in Africa. In recent years, it was reported that surface hydrophobic-modified nanoparticles have important applications in crude oil flow modification. In this work, four kinds of core-shell hybride nanoparticles by grafting poly (octadecyl, docosyl acrylate) and poly (acrylate-α-olefin) onto the surface of nano-sized SiO2 were synthesized by grafting polymerization method. The chemical structure of nanoparticles was analyzed by Fourier transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM) and thermogravimetric analysis (TGA). The rheological behaviors of crude oil and precipitation of asphaltenes in the presence of nanoparticles were studied by measuring the viscose-temperature relationship curve, the cumulative wax precipitation amount, and morphology of waxes and asphaltenes. The results indicate that the docosyl polyacrylate@SiO2 nanoparticle (PDA@SiO2) can reduce the cumulative wax precipitation amount of crude oil by 72.8%, decline the viscosity of crude oil by 85.6% at 20 °C, reduce the average size of wax crystals by 89.7%, and inhibit the agglomeration of asphaltene by 74.8%. Therefore, the nanoparticles not only adjust the crystalline behaviors of waxes, but also inhibit the agglomeration of asphaltenes. Apparently, core-shell hybride nanoparticles provides more heterogeneous nucleation sites for the crystallization of wax molecules, thus inhibiting the formation of three-dimensional network structure. The core-shell polymer@SiO2 hybride nanoparticles are one of promising additives for inhibiting crystallization of waxes and agglomeration of asphaltenes in crude oil.

Investigation of the Stability Mechanism of Stimulus-Responsive Wormlike Micelle-CO2 Foams in the Oil Phase.

Foam flooding is an important tool for reservoir development. This study aims to further investigate the interaction between stimulus-responsive wormlike micelle (WLM)-CO2 foams and crude oil. We performed micromorphology experiments as our major studies and used molecular dynamics simulations as an auxiliary tool for interfacial analysis. We utilized foam generation, liquid separation, and defoaming as the entry points of experimental research and energy as the quantitative assessment index to investigate the dynamic process of the action of different oil contents and oil phase types in a DOAPA@NaSal-H+ foam system. We also examined the role of NaSal in the generation and development of the foam system. Results indicated that the law of crude oil's effect on foam could be summarized as "low contents are beneficial and high contents are harmful." In addition, although the DOAPA@NaSal-H+ foam system has high compatibility for saturated and aromatic hydrocarbons, it is highly suitable for application in reservoir environments with relatively high asphaltene and resin contents. Through combined experimental and simulation approaches, we clarified the law governing the stability of the DOAPA@NaSal-H+ foam system in different oil-containing environments, identified the key role of NaSal, and provided a reference for the targeted application of the DOAPA@NaSal-H+ foam system in different oil reservoirs.

Influence of a Precursor Catalyst on the Composition of Products in Catalytic Cracking of Heavy Oil

Heavy oils are characterized by a high content of resins and asphaltenes, which complicates refining and leads to an increase in the cost of refinery products. These components can be strongly adsorbed on the acid sites of a supported catalyst, leading to its deactivation. Currently, various salts of group 8 metals are being considered for such processes to act as catalysts during oil cracking. At the same time, the nature of the precursor often has a significant impact on the process of refining heavy oil. In this work, catalytic cracking of heavy oil from the Ashalchinskoye field using different precursors (nanodispersed catalysts formed in situ based on NiO) has been studied. The cracking was carried out at 450 °C with a catalyst content from 0.1 to 0.5 wt.%. The catalytic cracking products were analyzed via SARA, GC, XRD and SEM. Nickel acetate and nitrate promote similar yields of by-products, while formate promotes higher yields of gaseous products. Formate and nickel acetate were shown to produce 1.8 and 2.8 wt.% more light fractions than nickel nitrate. When heavy oil is cracked in the presence of Ni(NO3)2∙6H2O, the maximum decrease in sulfur content (2.12 wt.%) is observed compared to other precursors. It has been found that the composition and morphology of the resulting nickel sulfides and compaction products are influenced by the nature of the catalyst precursor. XRD and SEM analyses of coke-containing catalysts indicate the formation of Ni9S8 and Ni0.96S phases during cracking when nickel nitrate is used and the formation of NiS and Ni9S8 when nickel acetate and formate are used.

Interfacial Interaction and Fatigue Behavior of Asphalt Mastics

Rheological characteristics of five road bitumens with different group composition and penetration at 25оС from 60 to 115х0.1 mm and asphalt binders based on them with volume content of filler (mineral powder of MP1 grade) – 0.275 (mass ratio bitumen: filler – 1:1) have been determined in the range from 30 to -10оС on dynamic shear rheometer. The influence of temperature and frequency on the parameter of interfacial interaction K-B-G* and thickness of adsorbed layer of original and thermal oxidative aging samples of asphalt mastic has been investigated. It is shown that in all samples K-B-G* decreases with decreasing temperature and increasing test frequency. A decrease in K-B-G* and adsorbed layer thickness in mastics after aging was observed in the case of bitumen with Gestel colloidal index CI=0.46–0.53, defined as CI=(S+A)(/R+Ar), and was stability of K-B-G* and adsorbed layer thickness in the case of bitumen with CI=0.61. No relationship was found between group chemical composition of bitumen and adsorbed layer thickness in original mastics. In aged mastic the greater thickness of adsorbed layer has samples based on bitumen with higher content of asphaltenes. The peculiarities of fatigue behavior of bitumen and mastic in the linear amplitude sweep test were investigated. The correlation between the thickness of the adsorbed layer and the angle of slope of the curves of dependence of the maximum shear stress (τmax) on the complex modulus (G*) was noted for aged samples.

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.

Investigating the Impact of Hydrocarbon Solvent on In-Situ Asphaltene Precipitation in Solvent-Assisted Cyclic Steam Technique

Summary Heavy oil recovery techniques often confront a significant challenge in in-situ asphaltene precipitation. This procedure significantly affects the characteristics of reservoirs and impedes optimal oil extraction. The purpose of this research was to examine how hydrocarbon solvents affect asphaltene precipitation occurring naturally in the reservoir as well as the resulting asphaltene content in processed oil. This was conducted using a laboratory-level dynamic model and the solvent-assisted cyclic steam stimulation (CSS) method. Throughout this experiment, which comprised six cycles, the steam-solvent blend’s pressure was consistently maintained close to 680 psi and the temperature was maintained at 500°F at the injection point. The findings revealed crude oil cracking at this temperature and noticeable in-situ asphaltene precipitation during the solvent-assisted CSS process. Notably, asphaltenes demonstrated mobility within porous media, contributing to their production in subsequent CSS cycles. Compared to a steam-only CSS control experiment, a higher asphaltene content in the original oil was observed, indicating that thermodynamic changes during the experiments likely caused asphaltene cracking. To sum up, this research provides an understanding of the effects of heavy oil recovery methods that rely on solvents on the precipitation of in-situ asphaltene and the content of asphaltene in the refined oil.

Probing the interaction between asphaltene-wax and its effects on the crystallization behavior of waxes in heavy oil via molecular dynamics simulation

High content of asphaltenes and waxes leads to the high pour point and the poor flowability of heavy oil, which is adverse to its efficient development and its transportation in pipe. Understanding the interaction mechanism between asphaltene-wax is crucial to solve these problems, but it is still unclear. In this paper, molecular dynamics simulation was used to investigate the interaction between asphaltene-wax and its effects on the crystallization behavior of waxes in heavy oil. Results show that molecules in pure wax are arranged in a paralleled geometry. But wax molecules in heavy oil, which are close to the surface of asphaltene aggregates, are bent and arranged irregularly. When the mass fraction of asphaltenes in asphaltene-wax system (ωasp) is 0–25 wt%, the attraction among wax molecules decreases and the bend degree of wax molecules increases with the increase of ωasp. The ωasp increases from 0 to 25 wt%, and the attraction between asphaltene-wax is stronger than that among waxes. This causes that the wax precipitation point changes from 353 to 333 K. While the ωasp increases to 50 wt%, wax molecules are more dispersed owing to the steric hindrance of asphaltene aggregates, and the interaction among wax molecules transforms from attraction to repulsion. It causes that the ordered crystal structure of waxes can't be formed at normal temperature. Simultaneously, the asphaltene, with the higher molecular weight or the more hetero atoms, has more obvious inhibition to the formation of wax crystals. Besides, resins also have an obvious inhibition on the wax crystal due to the formation of asphaltene-resin aggregates with a larger radius. Our results reveal the interaction mechanism between asphaltene-wax, and provide useful guidelines for the development of heavy oil.

Comparative Analysis of High-Viscosity Oils from the Khanty-Mansi Autonomous Okrug and the Naftalan Oil Field to Assess Their Balneological Potential

The physicochemical properties, fractional composition, structural-group composition, molecular composition, and the content of individual SARA fractions were characterized for high-viscosity naphthenic crude oils of the Pokur Formation produced in Khanty-Mansi Autonomous Okrug (KhMAO), Russia in comparison with therapeutic oil from the Naftalan oil field, Azerbaijan. All the tested oil samples exhibited high density (0.922– 0.956 g/cm3), high boiling points (164–199°C), high molecular weights (302–424 g/mol), and low paraffin content (0.04–0.42 wt %). The greatest similarity in terms of compositions was observed between the samples from the Naftalan and KhMAO-1 oil fields. The SARA analysis revealed a high content of resins and asphaltenes in crude oils from the KhMAO-2 field. This explains the distinctive features of the fractional composition (examined by SimDis simulated distillation) and structural-group composition (n–d–M method) of this sample, specifically its higher content of unevaporated residue (i.e., components that boil above 500°C), higher concentrations of naphthenic and aromatic carbons, and increased ring numbers in ring structures. GC/MS characterization of the molecular composition showed, for all samples, identical sets of adamantane and its homologues, as well as sesquiterpanes, steranes, tricyclic terpanes, aromatic steroids, and, to some extent, naphthalenes. The paraffin-naphthenic fractions of the Naftalan and KhMAO-1 oils consisted mostly of isoprenoid alkanes, and phenanthrenes predominated among the aromatic fractions of these samples. Furthermore, the Naftalan and KhMAO-1 crude oils were similar in the concentrations of adamantanes and decalines. The revealed similarity in the molecular, structural-group, and fractional compositions and in the SARA analysis between the KhMAO and Naftalan crude oils offers good opportunities for alternative uses of the Pokur high-viscosity oils from the KhMAO oil fields as analogs of Naftalan oil and promising raw materials for the production of therapeutic products for the purposes of balneology and practical health care.

Movable and non-movable hydrocarbon fractions in an oil-depleted sandstone reservoir considered for CO2 storage, Nini West Field, Danish North Sea

The Paleocene–Eocene quartz- and glauconite-rich reservoir sandstones of the depleted Nini West oilfield in the Siri Canyon, Danish North Sea, are considered a CO2 storage site. Mobilization of the remaining oil in the reservoir by the injected supercritical CO2 (scCO2) can cause oil displacement and potentially clogging of pore throats by the non-soluble heavy oil fraction. This study focuses on the movable and non-movable oil and solid bitumen/asphaltenes fractions present in the Nini West reservoir, including the effect of scCO2 injection on the residual oil. The residual oil in 14 samples from 13 core plugs from the oil-leg of the Nini-4 well was analyzed, as well as the extracted oil from preserved samples and the Nini stock tank oil (STO). The samples were acquired from preserved, cleaned, restored, and scCO2 flooded core plugs and were analyzed by organic geochemistry, including extended slow heating pyrolysis (ESH®) and organic petrography. The STO is paraffinic with a fairly high asphaltene content, and the preserved samples show that the residual oil occurs in association with glauconite clasts. The extracted oil consists mainly of movable oil fractions and a smaller amount of non-movable oil and solid bitumen/asphaltenes. The organic solvents used in different cleaning methods could remove most of the oil in the samples, but none of them can completely remove the solid bitumen/asphaltenes adhered to the glauconite clasts. The orange-brownish fluorescing solid bitumen/asphaltenes occur in the interior of the glauconite clasts, as coatings on the surface, and in small cracks in the surface, as well as between the laminae of glauconised mica. A sample from a cleaned core that has been restored to original wettability condition while controlling oil and brine saturations, and aged for a month at reservoir conditions, has an oil composition akin to the preserved samples. By scCO2 flooding, the movable oil fractions are entirely removed while the solid bitumen/asphaltenes coatings and remnants in the interior of the glauconite clasts are not mobilized. The presence of solid bitumen/asphaltenes in the organic solvent cleaned samples and in the scCO2 flooded sample suggests that these compounds are highly non-movable. Furthermore, a low proportion of heavy non-movable oil in the scCO2 flooded samples indicates minor asphaltenes precipitation, perhaps due to the high permeability and homogeneity of the sandstones.

Experimental study on the rheological characteristics and viscosity-enhanced factors of super-viscous heavy oil

To reveal the viscosity-enhanced mechanism of super-viscous heavy oil and improve the recovery rate of super-viscous heavy oil, the four components, elemental composition, rheological properties, and effects of asphaltenes and resin on the viscosity of super-viscous heavy oil from well TH12434 in Tahe Oilfield, China have been analyzed from macro and microscopic perspectives by Anton Paar rotational rheometer, gas chromatography-mass spectrometry and scanning cryo-EM to solve the problems of poor fluidity and high asphaltene content. The experimental results showed that in the temperature range of T= 40-100°C, the viscosity of super-viscous heavy oil decreases sharply from 352000 mPa∙s to 1620 mPa∙s, and the super-viscous heavy oil exhibits clear thermo-sensitivity. With T= 100°C and shear rate ranging from γ= 0-800 s-1, the viscosity of super-viscous heavy oil decreases sharply from 45000 mPa∙s to 956 mPa∙s, and the oil sample shows typical pseudoplasticity. The baseline of super-viscous heavy oil analysis by gas chromatography shows too high, and more than 80 % of super-viscous heavy oil compounds have a matching degree of less than 70 % with standard compounds, indicating that the super-viscous heavy oil had poor heterogeneity and many impurities. It is observed by scanning cryo-EM that the micromorphology of super-viscous heavy oil is large granular, strong continuity, asphaltene micromorphology presents an obvious layered structure, the layer spacing is 637.7 nm, and its asphaltene molecules form an order-like or crystal-like association structure through several unit sheet layers, resulting in high viscosity of super-viscous heavy oil. Based on the analysis results of the influencing factors of the viscosity of super-viscous heavy oil, a theoretical basis for the selection of viscosity reduction technology for super-viscous heavy oil the efficient exploitation in Tahe Oilfield, China could be provided.

Experimental screening of various asphaltene deposition inhibitors for utilization in flowlines

This study presents a systematic experimental screening approach to scrutinize the efficacy of various inhibitors for two distinct crude oils (named A and M). The crudes possessed relatively high asphaltene content suffering from asphaltene deposition issues in flowlines. For this purpose, a set of static and dynamic tests were conducted for 16 chemical inhibitors. Modified asphaltene dispersion test (ADT) was mainly used for synthetic oils of SM and SA, made up of crude oils M and A, respectively. The samples were later subjected to inhibitors to monitor their inhibition performance, and thermal stability. DBSA was observed to outperform other chemicals, with an efficiency of 97%. However, its applicability was limited in fields under consideration where both water production and asphaltene deposition occur simultaneously. Branched DBSA, palmitic acid, and phthalic acid, at 1000 ppm, showed 52%, 41%, and 39% efficiencies, respectively. A lower centrifugal force, applied during ADT, improved the efficiency of 110, a commercial chemical, by over 2.5 times to 71%, suggesting its superior dispersion capabilities over inhibition. Thus, it was revealed that the ADT-based method at strict centrifugal conditions would underestimate the performance of dispersants. Furthermore, using the modified ADT on crude oil M revealed that DBSA, branched DBSA, and phthalic acid, at 1000 ppm, had 74%, 65%, and 58% efficiencies, respectively. Time scan turbidimetry showed also 67%, 51%, 49%, and 42% suspension of particles after 80 min in the presence of 66.6 vol% n-C7 for DBSA, branched DBSA, dispersant 110, and phthalic acid. Finally, results obtained from the capillary deposition flow (CDF) test at 70 °C, showed that dispersant 110 would have the most promising performance since 50% reduction for pressure drop was experienced. This chemical is deemed suitable due to low efficiency of DBSA in cases where water would co-produced with oil.

Cyclopentane hydrate wettability measurements used to evaluate the efficacy of oil natural surfactants using ultra-low volume samples

Hydrate surface wettability is a fundamental aspect to better understand agglomeration present in oil bearing petroleum pipelines. Coupling these measurements with hydrate film growth gives further information on kinetic effects that may also be present from natural surfactants in different oils. In situ measurements of wettability (quantified by the contact angle) and film growth rates were performed on cyclopentane hydrate surfaces at atmospheric pressure and subcooling of 4 °C. Contact angle and film growth results were obtained for the baseline system (pure cyclopentane), one model oil, and seventeen natural oils (diluted to 0.02 vol% in cyclopentane). Results showed a wide variety of contact angles and film growth values where higher asphaltene contents in the oils corresponded to higher contact angles and lower film growth rates, thought to be from better alignment of natural surfactant molecules at the hydrate/hydrocarbon interface. It was also shown for select oils that increasing the oil concentration in the cyclopentane increases the contact angle and decreases the film growth rate compared to the baseline system. For select oils that had higher contact angles, increasing the water content of the system decreases their contact angle and film growth compared to the baseline system. Isolating different oil fractions for select oils also shows which fractions tend to play a larger role in wettability behavior. Typically, the fractions with more surface active components (asphaltene and resins) are shown to contribute to the higher contact angle and slower film growth rates for select oils. Evidence of the competition between film growth and capillary suction of water into the hydrate has been shown, and a mechanistic breakdown of three different transient scenarios has been proposed. Each of these observed interfacial behaviors gives information on what can be expected from larger scale phenomena, including hydrate agglomeration, with very small oil samples.

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.

Factors and Kinetics Related to the Formation of Heavy Oil-in-Water Emulsions

Oil-in-water emulsions provide an essential contribution to enhanced oil recovery by acting as oil displacement and conformance control systems. However, the dominant factors affecting their emulsification and kinetics are unclear. The emulsification rate is usually defined in terms of changes in the torque, conductivity, or particle size over time, which results in inaccurately calculated emulsified oil amounts. Therefore, the effects of temperature, pH, and NaCl concentration on the emulsified mass and droplet sizes of aqueous emulsions of Jin8-7 and Chen373 oil with octadecyl amine ethoxylate ether as an emulsifier were investigated. The results showed that the formation of oil-in-water emulsions of Jin8-7 and Chen373 under different conditions occurred via a two-stage mechanism: rapid emulsification and emulsion maturation. The emulsified oil mass rapidly increased during the rapid emulsification period and plateaued during the emulsion maturation period. This indicates that the emulsified oil mass largely depended on the short rapid emulsification period. It was also found that increasing the temperature and pH were more conducive to the emulsification of Chen373 oil with a high viscosity and high asphaltene content. The optimal NaCl concentration was determined to be 2% and 4% for Chen373 and Jin8-7 oil, respectively, based on the emulsification mass during the rapid emulsification period. The droplet size decreased first and then increased during the emulsification process under most experimental conditions. A second-order kinetics model for emulsification was proposed, in which the evolution of emulsified oil mass calculated with time agreed with the experimentally measured values. This study can provide theoretical guidance for the implementation of chemical cold production of heavy oil in oilfields.