Amount Of Asphaltene Research Articles

Determination of Asphaltenes in Petroleum Crude Oils by Fourier Transform Infrared Spectroscopy

An analytical method was developed to quantitatively determine the asphaltene content in petroleum crude oils by Fourier transform infrared spectroscopy (FT-IR). Asphaltenes are a solubility class of compounds found in crude oils. They are black to dark brown solids defined by their insolubility in n-alkane solvents. The structure of asphaltene molecules is polynuclear aromatic rings with alkyl side chains and heteroatoms such as nitrogen, oxygen, and sulfur attached. Asphaltenes are known to cause oil well plugging and irreversible catalyst deactivation in refineries. The asphaltene content of 50 crude oils from a wide array of geochemical conditions was determined by the standard n-pentane insolubles method. FT-IR spectra of the 50 crude oils were collected using an attenuated total reflectance cell. A partial least squares model was generated to predict the amount of asphaltenes from 42 of the crude oils. The model was shown to have an R2 value of 0.95 and a standard error of estimate of 0.92 wt %. An ...

A new viscosity model for petroleum fluids with high asphaltenes content

A compositional model for predicting the viscosity of petroleum fluids as a function of temperature and pressure has been developed. It is based on a mixing rule that takes into account the compositional information, and on the model of Kanti et al. [1]for the dependence on pressure and temperature. The approach of Grunberg and Nissan [2]is used in order to take into account the fluids composition. Four different fractions are used: Gas, C 6–C 20, C 20+ (saturates+aromatics+resins), and C 20+ (asphaltenes). This model is designed so as to be valid in a large compositional range, especially for liquids containing large amounts of asphaltenes. The model of Kanti uses a single viscosity value for predicting fluid viscosity at any pressure and temperature. Its universal parameters have been fitted on a large database ranging up to 100 MPa in pressure and up to 120°C in temperature. The validation of this new model on 76, so far, unpublished experimental data points of crude oils, covering a dynamic viscosity range from 2 to 23,298 mPa s, led to an absolute mean deviation of 24%.

A Study of Multilayer Adsorption of Asphaltenes on Glass Surfaces by Photothermal Surface Deformation. Relation of This Adsorption to Aggregate Formation in Solution

Adsorption of asphaltenes on glass surface has been studied by using photothermal surface deformation spectroscopy. This technique was adapted for direct measurement of the amount of asphaltene adsorbed on glass plate surfaces. Solid-solution adsorption isotherms for asphaltenes were obtained at room temperature in toluene. Stepwise or multilayer adsorption was detected in the three cases examined (Furrial, Jobo, and Hamaca) after long contact periods. After the first layer due to glass surface saturation one (Jobo and Hamaca) or two (Furrial) further layers were measured. Analysis of results suggests that this adsorption behavior could be related to the sudden increase of aggregate concentration typical of micelle formation. For instance, below 4000 mg/L Furrial asphaltenes behave like a mixture containing two surfactants with cmc of 1500 and 3000 mg/L, respectively. A slow increase in molecular weight when measured in toluene was observed for Hamaca (from 4230 to 17420) and Cerro Negro (from 5350 to 15170) over a 3 day period, suggesting a slow formation of aggregates. Accordingly, the above stepwise adsorption takes a long time to appear (more than 3 days). Isotherms measured at shorter times only showed a continuous but not stepwise increase in adsorption with concentration.

Geochemical monitoring of waxes and asphaltenes in oils produced during the transition from primary to secondary water flood recovery

Results are presented on changes in the content and composition of waxes and asphaltenes of oil produced during the transition from primary to secondary recovery following water flooding. Oil samples have been collected for a period of about three years from one well in Prairie Gem field in central Oklahoma. Wax and asphaltene fractions have been isolated from the produced oils and analyzed, qualitatively and quantitatively, by high temperature gas chromatography. The results demonstrate significant variations in the asphaltene and wax content of the oil produced during the transition period from primary to secondary water flood recovery, ranging from 0.7 to 5 wt%, and 11 to 33 wt%, respectively. Moreover, these variations are found to be accompanied by changes in wax composition and to precede specific production events. The oil produced a month before the response of the well to water flooding indicated an enhanced concentration of nC 22–C 35 alkanes in the wax. The following episode of wax plugging in well equipment was preceded by increased amounts of asphaltenes and high molecular weight (nC 35–C 50) alkanes in the wax of produced oils. Changes in the asphaltene and wax compositions are discussed in terms of processes displacing weakly adsorbed organic material from the pore spaces of the reservoir under increased reservoir pressure and flowing fluid volumes related to water flooding.

CHANGE OF PHYSICAL AND THERMAL DECOMPOSITION PROPERTIES OF IN SITU HEAVY OIL WITH STEAM TEMPERATURE

ABSTRACT Ikiztepe crude oil was subjected to four different steam temperatures during steam injection which was applied as an enhanced oil recovery process on a linear limestone model saturated with oil. Produced oils were characterized using density, viscosity measurements, pyrolysis experiments utilizing TGA and elemental analysis runs. Results showed that produced crude oils change in measured characteristics as compared to the original oil. These changes include an increase in H/C, and cracking activation energy, decrease in density, viscosity and amount of residue remaining after cracking (coke). Also, decrease in asphaltene amount, changes in the elemental composition of asphaltenes and increase in the cracking activation energies were observed at 225 °C run. These measurements show that the produced oils get lighter and differ compositionally from the original oil as steam temperature increases. Decrease in elemental sulphur amount is one of the major changes when environmental considerations are concerned. Residual oil left in the limestone pack on the other hand shows an increase in the low temperature oxidation (LTO), fuel deposition (FD) and high temperature oxidation (HTO) activation energies as determined from TGA combustion experiments on the samples taken from the pack after steam injection experiments.

Ageing of interfacially active components and its effect on emulsion stability as studied by means of high voltage dielectric spectroscopy measurements

Interfacially active components (asphaltenes and resins) have been extracted from North Sea crude oils and aged at 50°C. Model water-in-oil emulsions have been stabilized by these compounds in different amounts and ratios. The stability of these emulsions has been established by means of critical electric fields measured by time domain dielectric spectroscopy in the presence of an external electric field. It is found that the stability depends mainly on the amount of asphaltenes, the degree of aging of asphaltenes and resins and the ratio between asphaltenes and resins.

A Multivariate Screening Analysis of W/O Emulsions in High External Electric Fields as Studied by Means of Dielectric Time Domain Spectroscopy, II: Model Emulsions Stabilized by Interfacially Active Fractions from Crude Oils

The electrically induced coalescence of water-in-oil emulsions stabilized by interfacially active fractions from crude oils has been studied by means of time domain dielectric spectroscopy at high electric fields. The experiments were designed with a 27-3reduced factorial design. Regression analysis clearly shows that the choice of organic solvent and the amount of asphaltenes, as well as the interplay between these variables, are the most significant parameters for determining the stability of these emulsions. It should be pointed out that the asphaltenes were the only surface active fraction tested. No interplay between, for instance, asphaltenes and resins was investigated. The nonlinearity found in the regression analysis is explained by different aggregation states of asphaltenes in aliphatic and aromatic solvents. The influence of the variables upon the emulsion stability is discussed.

Comparison of the Hydrophilicity/Hydrophobicity of Illites and Kaolinites

Asphaltene and water adsorption isotherms on clay surfaces have been determined to approach the hydrophilic/hydrophobic character of several samples of kaolinites and illites. It is shown that the nature and the genesis condition of the clays affect the adsorption of both asphaltene and water. A larger amount of asphaltene is adsorbed on kaolinites while illites show more affinity for water. Cation hydration is shown to be responsible for part of the total hydrophilicity of the clays. It is also found that 25% of the kaolinite surface is hydrophilic, whereas this value extends to 40% for illite. Finally, it is shown that hydrophilicity decreases, whereas asphaltene adsorption increases.

95/01288 Oil and money. Economic theory and the Brent System

The effect of deasphalting of heavy oil with different degrees of asphaltenes precipitation on catalytic hydrotreating is reported in this work. Deasphalted oils were obtained in a pressurized vessel using n-heptane and n-pentane as solvents. Various samples with different amounts of asphaltenes were prepared by varying precipitation conditions. Hydrotreating of deasphalted oils was conducted with a commercial NiMo catalyst in a batch reactor at the following reaction conditions: hydrogen pressure of 100 kg/cm2, temperature of 400 °C, stirring rate of 750 rpm and reaction time of 4 h. The heavy oil, the deasphalted oils and the hydrotreated products were characterized by sulfur, metals (Ni, V), asphaltene contents, and API gravity. Metals and carbon contents as well as textural properties and X-ray diffraction were also determined on fresh, spent and regenerated catalysts.

95/01292 Vietnam oil and gas update

The effect of deasphalting of heavy oil with different degrees of asphaltenes precipitation on catalytic hydrotreating is reported in this work. Deasphalted oils were obtained in a pressurized vessel using n-heptane and n-pentane as solvents. Various samples with different amounts of asphaltenes were prepared by varying precipitation conditions. Hydrotreating of deasphalted oils was conducted with a commercial NiMo catalyst in a batch reactor at the following reaction conditions: hydrogen pressure of 100 kg/cm2, temperature of 400 °C, stirring rate of 750 rpm and reaction time of 4 h. The heavy oil, the deasphalted oils and the hydrotreated products were characterized by sulfur, metals (Ni, V), asphaltene contents, and API gravity. Metals and carbon contents as well as textural properties and X-ray diffraction were also determined on fresh, spent and regenerated catalysts.

SHORELINE OIL FROM EXXON VALDEZ: CHANGE FROM 1991 TO 19931

ABSTRACT During summer of 1993, the Alaska Department of Environmental Conservation surveyed 45 sites in Prince William Sound that were oiled by the March 1989 Exxon Valdez oil spill. The data describe the oil's visual properties and extent. Comparisons provide estimates of oil reduction since 1991. From 1991 to 1993, an estimated 50 percent reduction in the amount of asphalt, surface oil residue, and mousse was largely caused by manual removal and raking. Subsurface oil reduced by about 65 percent. Sites mechanically tilled or from which oiled sediment was removed improved the most, but natural reduction was still greater than 50 percent.

Screening of Crude Oils for Asphalt Precipitation: Theory, Practice, and the Selection of Inhibitors

Summary This paper describes a simple method to screen crude oils for their tendency to precipitate asphalt, which may cause problems during production. The method is based on a thermodynamic model of asphalt solubility, derived earlier by Flory and Huggins. The most important parameters in this model are the Hildebrand solubility parameters for oil and asphaltene, and their molar volumes. The oil parameters can all be correlated with the in-situ density of the crude. The relative change in asphalt solubility in the crude per unit pressure drop is shown to be highest for light crudes that are undersatu-rated with gas, which usually contain only a small amount of asphaltenes. Hence, the chance that asphalt will precipitate will be greatest for these light crudes. For pressures below the bubblepoint, depres-surising of the crude will cause a rapid increase in asphalt solubility, due to changes in liquid composition. It is shown that heavy crudes usually will give fewer problems with asphalt precipitation, despite their higher asphaltene content, certainly if the reservoir pressure is close to bubblepoint pressure. Consequently, the tendency for asphalt precipitation is mainly determined by three parameters: the extent to which the crude is under-saturated with gas, the density of the crude at reservoir conditions, and its saturation with asphalt at downhole conditions. Apart from the simple screening method, more elaborate methods are described to assess the potential for asphalt precipitation more accurately; asphaltene analysis on produced reservoir fluid and tank oil; n-heptane titration of the tank oil; visual inspection of a bottom-hole sample in a high-pressure cell during pressure reduction; and dynamic flow tests on tank oil after η-heptane addition. An ultrasonic back scattering technique is described for monitoring the influence of different asphalt precipitation inhibitors. Using above techniques asphalt precipitation inhibitors have been identified that can be applied in the field.

Deactivation of a coal liquefaction catalyst

The effect of deasphalting of heavy oil with different degrees of asphaltenes precipitation on catalytic hydrotreating is reported in this work. Deasphalted oils were obtained in a pressurized vessel using n-heptane and n-pentane as solvents. Various samples with different amounts of asphaltenes were prepared by varying precipitation conditions. Hydrotreating of deasphalted oils was conducted with a commercial NiMo catalyst in a batch reactor at the following reaction conditions: hydrogen pressure of 100 kg/cm2, temperature of 400 °C, stirring rate of 750 rpm and reaction time of 4 h. The heavy oil, the deasphalted oils and the hydrotreated products were characterized by sulfur, metals (Ni, V), asphaltene contents, and API gravity. Metals and carbon contents as well as textural properties and X-ray diffraction were also determined on fresh, spent and regenerated catalysts.

The influence of carboxylic acid content on bitumen viscosity

Bitumens from six diverse tar sand deposits were obtained by toluene extraction. The viscosities of each of the bitumens were determined in the temperature range 60 to 90 °C and were found to be Newtonian in character. All bitumen samples were fractionated using a modified SARA (saturates, aromatics, resins and asphaltenes) type analysis. The separated fractions were examined by transmission and specular reflectance FT-i.r. spectrsocopy (SR-FT-i.r.). The FT-i.r. analysis indicated that carboxylic acid present in the bitumen accumulated in the polar fractions, particularly in the resin fraction. The carboxylic acid concentration was estimated from its characteristic FT-i.r. absorbance band by the band-fit method. The carboxylic acid in the resin fractions was also estimated by a potentiometric titration method using a mixed solvent. Although it was clearly indicated from the infrared analysis of the bitumen fractions that bitumens with higher viscosity generally contained larger amounts of carboxylic acid, a simple quantitative relationship between these two variables to the exclusion of others in a complex material such as bitumen was found to be difficult. The viscous nature of the bitumen is principally attributed to the internally suspended asphaltene particles. The fractional compositions of the various bitumens clearly indicated that the viscosity of a given bitumen cannot always be correlated with its asphaltene content alone. However, the introduction of another variable, namely the carboxylic acid content of the bitumen, together with asphaltene content can better account for the property of viscosity. The Athabasca sample was the least viscous of all the bitumens under study, although it contained an intermediate amount of asphaltenes. FT-i.r. analysis indicated that the Athabasca resin fraction contained only a small amount of acid and was explained to be inadequate to optimally engage the asphaltenes in suspension through hydrogen bonding. In addition, it was shown that the major oxygen functional group in Athabasca bitumen is an ester which was believed to be not as efficient as an acid in the hydrogen bond formation. The presence of esters in the Athabasca resin fraction was confirmed by the hydrolysis of the resin fraction and analysis of the hydrolysis products by SR-FT-i.r. The influence of carboxylic acid and asphaltene contents on bitumen viscosity is discussed with reference to the structural model developed by Nellensteyn.

Macrostructure of asphaltenes in vacuum residue by small-angle X-ray scattering

Small-angle X-ray scattering was used to investigate the macrostructure of the asphaltenes (heptane-insolubles) in Duri, Ratawi, Oriente and Merey vacuum residues at 93 °C. Synthetic vacuum residues prepared from these materials with different amounts of asphaltenes were also studied. To determine the shape and average size of the colloidal particles, the measured scattering intensities were fitted by applying the constraint that the contrast must remain independent of shape and size distribution parameters as the asphaltene concentration is varied. According to this analysis the asphaltenic colloidal particles appear spherical. The average radii are in the range 30–60 Å, depending on the crude oil; the radii obey the Schultz distribution. The degree of polydispersity is ~15%. The average particle size does not appear to depend on heteroatom content. Larger asphaltenic particles appear to dissociate when vacuum residue is diluted with the non-asphaltenic fraction.

Effect of process parameters on the coprocessing of coal and heavy oils

The effect of process parameters on the combined coprocessing of coal and heavy residua was investigated. The kinetics of product distribution for the reaction of an Illinois No. 6 coal and two different residua was studied as a function of temperature and hydrogen pressure. The reaction products were separated by solvent fractionation into oils, asphaltenes, preasphaltenes and insoluble organic matter (IOM). The extraction process appears to be strongly dependent upon the asphaltene content of the solvent. At 450°C in the case of North Slope and at 425°C when Maya Crude was employed, the amount of IOM obtained increases with time due to retrograde reactions. With increasing severity, the yield of oils falls off, but the amount of asphaltenes and preasphaltenes in the THF soluble fraction decreases. Some interaction between coal and residuum reactions was detected from the comparison between hydropyrolysis and coprocessing runs.

Measurement And Correlation Of Asphaltene Precipitation From Heavy Oils By Gas Injection

Abstract The nature of asphaltenes and their role in the production and processing of crude oils has been the topic of numerous studies. This is due to the fact that the economics of oil production can be seriously affected by the asphaltene deposition problem. This paper presents a novel method to visualize in situ asphaltene precipitation from heavy oils with light hydrocarbon gases, e.g. methane. propane, ethane/propane mixtures, and carbon dioxide at reservoir pressures and temperatures. Experimental results are reported for the effects of temperature (up to 100 °C), pressure (up to 20 MPa) and composition on the formation of asphaltene precipitates from heavy crude oils. A series of titration experiments were conducted with several n-alkanes to determine the amount of asphaltenes precipitated. Both the amount and nature of the precipitate varied with the solvent used. Propane was the most prolific of all the solvents used in precipitating asphaltenes from the heavy oils. A thermodynamic model proposed by Hirshberg et al. was used to correlate the experimental data. Introduction Miscible and immiscible flooding of crude oil reservoirs by light hydrocarbon gases, carbon dioxide and other injection gases has become a popular method for enhanced oil recovery(1). The flooding process, however, causes a number of changes in the flow and phase behaviour of the reservoir fluids and can significantly alter rock properties. Such changes include the precipitation of asphaltenes(2) and wettability reversal which can alter recovery efficiencies. The existence of asphaltenes in crude oils and their deposition inside reservoirs and wellbores can cause severe problems and affect the efficiency and cost of petroleum production. The important parameters that affect asphaltene precipitation during gas injection are the compositions of the crude oil and the solvent gas, and the pressure and temperature of the reservoir(3–5). Precipitation of asphaltenes is a complex process and it is generally followed by flocculation which produces an insoluble material in the heavy oi1(6). Asphaltenes are believed to be stabilized in solution by resins and aromatics and the asphaltene/resin ratio plays a key role in their precipitation. This ratio is more important than the absolute asphaltene content in determining which crudes will be subject to precipitation. Problems arising from asphaltene deposition have been reported in the literarure(7,8) for many field projects. Some examples of these are the Ventura field in California(9), Hassi Messaoud field in Algeria(l0) and heavy oil fields in Venezuela(l1). Deposition of asphaltenes in the wellbore can be a serious production problem and may require frequent solvent washings and scrapings to maintain oil production(10). Significant damage can be caused during well acidizing because the acid can cause the asphaltenes to precipitate and form rigid films. Other problems associated with asphaltene precipitation are the seizure of downhole safety valves submersible pumps, hinderance in wireline operations and production restrictions. These problems are discussed in derail by Leontaritist(7). Presently asphaltenes are removed either by mechanical cleaning, chemical cleaning, or by manipulating reservoir conditions (for example, pressure, production rates, etc,)(10,12). The approach taken by the oil industry has been a remedial one.

A study of asphaltic cements and their fractions by thermogravimetry

Thermal degradation of a number of asphaltic cements and their fractions has been studied using thermogravimetry (TG). It was found that TG can be used to characterise each asphalt and detect changes in the original crude oil or the processing conditions. Also an estimate of the asphaltene content may be obtained by either a multiple regression equation or a simple correlation between the amount of asphaltenes in an asphalt and the mass loss in the temperature range 410–500°C.

Resins and asphaltenes in the generation and migration of petroleum

Petroleum is a stable colloidal sol, with a continuous transition from the smallest hydrocarbon molecules to the bulkiest micelles. Asphaltenes are the micellar fraction precipitated by n-hepatane; in the remainder, resins—the non-hydrocarbon fraction—are separated by liquid chromatography. Resins control the sol stability. All these considerations apply equally well to organic extracts of rocks. Asphaltenes are macromolecular compounds, comprising polyaromatic nuclei linked by aliphatic chains or rings of various lengths and sometimes functional groups. They appear to differ by the size, with a statistically identical distribution of aromatic nuclei and linking units. On the contrary, resins are an heterogeneous group; if the heaviest are close to asphaltenes, the smallest are distinctly different molecules —such as aliphatic acids and quinolines for examples. The functional homogeneity of asphaltenes result when they migrate from source-rocks to reservoirs, in essentially a size differentiation. Thus, asphaltenes compositional fingerprints are valuable tools for correlation purposes. Asphaltenes from rock extracts and the corresponding kerogens contain the same constituent macromolecular units. A consequence of this compositional similarity is that asphaltenes and kerogen undergo parallel evolution during burial heating. To a lesser extent, this is true also of resins, although they do not appear to contain exactly the same constituents as kerogen and asphaltenes. Similarly, the amounts of asphaltenes and resins in rock extracts show orderly variations during geological evolution. For a given level of thermal evolution, differences in the origin of organic matter in various rocks are reflected in compositional variation of resins and asphaltenes contained in the rock extracts. Their composition is less variable than for the corresponding kerogens and they are, therefore, more sensitive to experimental error. On the contrary, a comparison of the amounts of resins and asphaltenes enables detailed distinctions between samples. All the preceding observations can be interpreted as showing resins and asphaltenes as intermediates in the reactions which lead from kerogen to hydrocarbons. However, they are not obligatory intermediates. Hydrocarbons can be produced directly from kerogen; the relative importance of resins and asphaltenes can be different in different situations. Resins and asphaltenes are valuable indicators of the origin of sedimentary organic matter in a rock and of its thermal evolution. Oil asphaltenes can be considered as reservoired kerogen moieties, and enable correlations with source-rock asphaltenes and parent kerogen. Asphaltene pyrolysis products are compositionally similar to the oil itself, when it has not suffered secondary alteration. Thus, pyrolysis of asphaltenes from degraded oils generates saturated hydrocarbon distributions similar to those of the original oil. Comparison of asphaltene pyrolysis products with the rock extract itself gives an indication of effects and degree of migration processes.

Particle—fluid interactions with application to solid-stabilized emulsions part I. The effect of asphaltene adsorption

Solid-stabilized water-in-oil emulsions are commonly encountered in the production of crude oil and synthetic fuel liquids. The ability of finely divided solids to stabilize these emulsions is due to the adsorption of asphaltenes and other heavy ends from the oil on the mineral surface which imparts to the solid its hydrophobic nature. This study presents results which quantify the particle—fluid interactions by means of adsorption measurements of asphaltenes on sodium montmorillonite particles. The influence of asphaltene adsorption on the contact angle at the water/oil/solid interface and on the zeta potential of the particles was investigated. The hydrophobic nature of the solids was found to be directly related to the amount of asphaltenes adsorbed on their surface. The effect of asphaltenes on the contact angle is explained in terms of the interfacial tensions at the oil/water and solid/water interfaces. The influence of pH and surfactant concentration in the aqueous phase on the contact angle and the zeta potential is assessed.