Asphaltene Deposition

The production and transportation of petroleum fluids could be severely affected by deposition of suspended particles (i.e. asphaltene, paraffin/wax, sand and/or diamondoids, in the production wells and/or transfer pipelines.  In many instances the amount of precipitation is rather large causing complete plugging of these conduits. Therefore, it is important to understand the behavior of suspended particles during flow conditions.
In this paper we present an overview of the heavy organics deposition problem, its causes, effects and preventive techniques. We also present an analysis of 􀀭he diffusional effects on the rate of solid particles deposition during turbulent flow conditions (crude oil production generally falls within this regime). We utilize the turbulent boundary layer theory and the concepts of mass transfer to explain the particle deposition rates on the walls of the flowing conduits􀀃 􀁺􀁻e developed model accounts for the Brownian and eddy diffusivities as well as for inertial effects and other forces acting upon the particles.
The analysis presented in this paper shows that rates of particle deposition (asphaltene, paraffin/wax, sand and/or diamondoids) on the walls of the flowing channels due solely to diffusional effects, are negligible. It is also shown that deposition rates decrease with increasing particle size. However, when the deposition process is momentum control􀀇ed (large particles) higher deposition rates are predicted. It is shown a decrease in deposition rates with increasing crude oil kinematic viscosity. An increase in deposition rates with increasing production rates is also observed.

Well-head production of petroleum can be significantly affected by flocculation, deposition, and plugging of asphaltene, paraffin/wax, and/or diamondoid inside the well. The economic implications of such a formation damage are tremendous. In this paper a comprehensive mechanism and predictive model for such compounds in oil wells is presented. This model is based on the macromolecular theory of polydisperse polymer and colloidal solutions, kinetics of aggregation, electrokinetic transport phenomena, and phase behavior of multicomponent mixtures. One question of interest in the oil industry is "when" and "how much" heavy organics will flocculate out under certain conditions. Since a petroleum crude generally consists of a mixture of light and heavy hydrocarbons and heavy organics it may be necessary to look at this problem from a more fundamental point of view than it has been the practice in the past. In this paper the author presents the cause-and-effect mechanisms of such depositions and introduces mathematical models to be used for preventive measures in various cases of petroleum production, transportation, and processing. With the application of the proposed model a number of predictive case studies are made. It is shown that with proper planning in the production scheme, consideration of the characteristics of the producing petroleum, injection fluid, well casing, and the reservoir it is possible to choose a formation-damage-free production scheme.

In an earlier study,1 oil−water interfacial tension was measured by the pendant drop technique for a range of oil-phase asphaltene concentrations and viscosities. The interfacial tension was found to be related to the relative surface coverage during droplet expansion. The relationship was independent of aging time and bulk asphaltenes concentration, suggesting that cross-linking did not occur at the interface and that only asphaltene monomers were adsorbed. The present study extends this work to measurements of interfacial rheology with the same fluids. Dilatation moduli have been measured using the pulsating droplet technique at different frequencies, different concentrations (below and above CNAC), and different aging times. Care was taken to apply the technique in conditions where viscous and inertial effects are small. The elastic modulus increases with frequency and then plateaus to an asymptotic value. The asymptotic or instantaneous elasticity has been plotted against the interfacial tension, indicating the existence of a unique relationship, between them, independent of adsorption conditions. The relationship between interfacial tension and surface coverage is analyzed with a Langmuir equation of state. The equation of state also enabled the prediction of the observed relationship between the instantaneous elasticity and interfacial tension. The fit by a simple Langmuir equation of state (EOS) suggests minimal effects of aging and of nanoaggregates or gel formation at the interface. Only one parameter is involved in the fit, which is the surface excess coverage Γ∞ = 3.2 molecules/nm2 (31.25 Å2/molecule). This value appears to agree with flat-on adsorption2 of monomeric asphaltene structures consisting of aromatic cores composed of an average of six fused rings and supports the hypothesis that nanoaggregates do not adsorb on the interface. The observed interfacial effects of the adsorbed asphaltenes, correlated by the Langmuir EOS, are consistent with the asphaltene aggregation behavior in the bulk fluid expected from the Yen−Mullins model.

Asphaltenes are a solubility class of petroleum crude oil that can destabilize and deposit in both upstream and downstream processes. In this study, asphaltene deposits were generated in metal capillaries by heptane addition to crude oils, and it was found that deposition is caused by submicrometer asphaltene aggregates. Deposits were generated at heptane concentrations above and significantly below the instantaneous onset point. Analysis of the results reveals that the governing factor controlling the magnitude of asphaltene deposition is the concentration of insoluble asphaltenes present in a crude oil-precipitant mixture and the instantaneous onset point is irrelevant to the deposition process. Electron microscopy images of the deposits represent the first images and confirmation of arterial growth in laboratory generated asphaltene deposits. The axial deposit profile was found to be highly nonuniform. In addition, deposits formed shortly after when oil and heptane mix, revealing that the destabilization of asphaltenes occurs virtually immediately after a precipitant is added. The results were reproduced with a second crude oil, indicating that asphaltene deposition behavior is broadly applicable.

The paper reviews the experiences of the oil industry and the progress and direction of the research community in their efforts to provide solutions to the asphaltene deposition problem. The oil industry, basically, seems to be com­bating the problem through remedial rather than preventive methods. Mechanical and chemical cleaning methods are being improvised to maintain production at economical levels. The research community, currently, is rather split in the approach to model the asphaltene deposition problem. One school of thought considers the asphaltenes dis­solved in the oil in a true liquid state and dwells upon thermodynamic techniques to predict their phase behavior. Another considers asphaltenes to exist in oil in a colloidal state, as minute suspended particles, and utilizes colloidal science techniques, among other, to predict their phase behavior. Experimental work over the last 40 years suggests that asphaltenes may exist in a colloidal state in the crude oil and further pursue of the subject in this direction by both the industrial and research communities is warranted.

The need for understanding of the nature of asphaltene in petroleum crude and it's role in EOR miscible gas flooding is well recognized according to the numerous research and developmental work underway in various laboratories. We have undertaken an interdisciplinary approach to the problem of asphaltene deposition from petroleum crudes. Our studies consist of the following topics: ( i) Molecular Thermodynamic modeling of phase behavior of aspheltene + petroleum crude+ injection gas systems and examination of the resulting successful models against the available laboratory and field data. (ii) Transport phenomena modeling of the flow of crude in porous media containing asphaltene colloidal particles (or micelles), colloidal instability which may cause asphaltene deposition, and wetability alterations due to the adsorption of asphaltene on the pore walls. (iii) Experimental measurements and simulation in support of our studies which consist of the following: (iii-1) Measurement of phase behavior of crude and injection gas mixtures at high pressures and at different GOR and temperature conditions (iii-2) Experimental simulation of flow through porous media of asphaltene-containing crude and injection gas.

Wettability is an important factor in a number of petroleum production processes. Asphaltene deposition can have a strong role in wettability reversal. Among many factors, the high molecular weight, polar fraction of crude oils, including the asphaltenes, are considered to be the primary wettability altering agents. Understanding the role of aspha1ltene in wettability of fluids on solid surfaces, and their reversal will help us plan for more efficient oil recovery processes. It will also establish the role of asphaltene deposition in the production operation of asphaltenic crudes including heavy petroleum crudes. In this paper the groundwork for the study of the complex role of asphaltene and its deposition in altering the wettability of reservoir fluids on solid surfaces is presented.  A number of experimental observations in support of the strong role of asphaltene in altering the interfacial properties and wettability is reported. A new molecular theory for prediction of wettability and its reversal is also introduced.

THE PRESENCE of asphaltene in heavy petroleum crudes causes a number of severe technological problems. One major problem is the untimely precipitation of asphaltene in the petroleum reservoir, in the wells, tubings and pipelines, and in the refinery components. At present, the oil industry basically is combating the problem of asphaltene deposition through remedial rather than preventive techniques. Mechanical and chemical cleaning methods are being improvised to maintain production, transportation and processing of petroleum at, or close to, non-economic levels. This paper illustrates the kind of economic barriers that asphaltene deposition may introduce and reviews the experiences of the oil industry with asphaltene precipitation. It also presents a descriptive account of the causes and preventive techniques of asphaltene flocculation.

The article was dedicated to the nanosystem application having synergistic effect developed on the basis of “low impact and excitation” effect for asphaltene-resin-paraffin (ARP) deposits prevention causing technological complications during the oil production and transportation. The nanosystem made on the basis of organic solvent, surface active substances (SAA) and metal nanoparticle simplifies the oil production, prevents mechanical mixtures in oil well equipment, solves the mixtures on down-hole zone and pipe, and decreases oil viscosity. Time between overhauls and oil production increased as the result of nanosystem application at the well № 1331 Palchig pilpile field of "Oil Rocks" OGPD, and great economic benefits were achieved.

Deposition of complex and heavy organic compounds, which exist in petroleum crude and heavy oil, can cause a number of severe problems. To prevent deposition inside the reservoir, in the well head and inside the transmission lines, it is necessary to be able to predict the onset and amount of deposition due to various factors. In the present paper, the mechanism of asphaltene deposition, which is the major cause of most organic deposition cases, is modeled based on statistical mechanics of polydisperse polymer solutions joined with the kinetic theory of aggregation and its predictive capability is discussed. Utilization of statistical mechanics of polydisperse polymer solutions joined with kinetic theory of aggregation enables us to develop a realistic model which is able to predict both reversible and irreversible heavy organic depositions. The present model is capable of describing several reversible and irreversible situations, such as the phenomena of organic deposition, growing...

Wettability is an important factor in a number of petroleum production processes. Asphaltene deposition can have a strong role in wettability reversal. Among many factors, the high molecular weight, polar fraction of crude oils, including the asphaltenes, are considered to be the primary wettability altering agents.
Understanding the role of asphaltene in wettability of reservoir fluids on solid surfaces, and its reversal will help us plan for more efficient oil recovery processes. It will also establish the role of asphaltene deposition in the production operation of asphaltenic crudes including heavy petroleum crudes.
In this paper the groundwork for the study of the complex role of asphaltene and its deposition in altering the wettability of reservoir fluids on solid surfaces is presented.  A number of experimental observations in support of the strong role of asphaltene in altering the interfacial tensions and wettability is reported. A new molecular theory for prediction of wettability and its reversal is also introduced.

The need to understand the nature of asphaltenes and asphalts & their role in the production, transportation and processing of crude oil is well­-recognized internationally, as manifested by the current activities·in the petroleum industry towards exploration, drilling, production and processing of heavier oils (higher in asphaltene content). Asphaltene deposition during oil production and processing ranks as one of the costliest technical problems the petroleum industry currently faces. In the present report, a colloidal model has been developed, capable of predicting the onset of flocculation of colloidal asphaltene in oil mixtures, due to either changes in composition (i.e., solvent addition) or electrical phenomena (i.e., streaming potential generation due to flow of asphaltenes containing oil· in conduits or porous media). For oil mixtures, from which flocculation is caused simply by flow, the model can make predictions as to the velocity ranges where colloidal asphaltene flocculation can be avoided. This could have a significant _impact on allowed reservoir drawdown rates, well spacing and tubing design.

The need to understand the nature of asphaltenes and asphalts & their role in the production, transportation and processing of crude oil is well­ recognized internationally, as manifested by the current activities·in the petroleum industry towards exploration, drilling, production and processing of heavier oils (higher in asphaltene content). Asphaltene deposition during oil production and processing ranks as one of the costliest technical problems the petroleum industry currently faces. In the present report, a colloidal model has been developed, capable of predicting the onset of flocculation of colloidal asphaltene in oil mixtures, due to either changes in composition (i.e., solvent addition) or electrical phenomena (i.e., streaming potential generation due to flow of asphaltenes containing oil· in conduits or porous media). For oil mixtures, from which flocculation is caused simply by flow, the model can make predictions as to the velocity ranges where colloidal asphaltene flocculation can be avoided. This could have a significant _impact on allowed reservoir drawdown rates, well spacing and tubing design. The present model is a part of a comprehensive asphaltene FRACTAL aggregation model (ASPHRAC) being developed at the University of Illinois.

In the present study, we report our findings on asphaltenic sludge formation onset during petroleum reservoir acidizing treatment. To achieve this goal, we perform a series of molecular dynamics (MD) simulations at high temperature and pressure (550 K, 200 bar) on asphaltenic-oil (containing different molecular structures of asphaltenes) /hydrochloric acid (HCl) systems. Our simulation results indicate formation of asphaltenic sludge onset due to reservoir acidizing. Accumulation of the ionized asphaltenes at the oil/aqueous interface is the cause of sludge formation onset. Presence of ionized asphaltenes at the oil/water interface is attributed to the strong ion-ion interaction between ionized asphaltenes and acid ions (H + and Cl-). Sludge formation onset is further stabilized via hydrogen bonding forces between ionized asphaltenes and interfacial water.

Carbon dioxide (CO 2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO 2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO 2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen-Mullins asphaltene model and were used to select the proper chemical to alter the oil's viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO 2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen-Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO 2 injection in different pore sizes, and correlates the results to the principle of the Yen-Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO 2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO 2 injection in hydrocarbon reservoirs.

Recently, we proposed a new technique for the determination of the onset of asphaltene flocculation ("Determination of the Onset of Asphaltene Flocculation: A Novel Method" SPE Production and Facilities May 1995. p.115-118]. This new method is based on viscosity measurements of a crude oil upon titration with a precipitating solvent (e ·8. n-pentane, n-heptane, etc.). The onset of asphaltene flocculation is detected by a sharp increase in the relative viscosity of the suspension in which asphaltene particle aggregation occurs. The key point in this development is the phenomenon of asphaltene flocculation induced by the addition of a n-paraffin hydrocarbon to a crude oil.
      In this paper, we validate the proposed new technique from a theoretical standpoint.

TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract At some thermodynamic conditions, asphaltenes flocculate into larger, almost spherical particles that have a specific gravity of 1.05 to 1.10. Work is cited here that indicates that asphaltene stable colloids exist in oil as very minute particles and that their pre-flocculation sizes are in the range of about 10 to 15 Å. This corresponds to 334 and 1,128 molecular weight respectively, assuming asphaltene spherical colloids and an experimentally determined asphaltene density of 1.06 g/cm 3. The reason for this high specific gravity of asphaltene particles compared to the rest of the molecules of oils is that they consist mostly of asphaltenes and resins, the heaviest constituents of oils. Roughly, resins have specific gravities of 0.95 to 1.0 and asphaltenes 1.1 to 1.2. Because of their high specific gravity asphaltene particles settle by the force of gravity in storage systems where the convection currents and shear forces are minimal. Some of these particles are large enough to overcome the convection currents and shear forces and settle in large separators and occasionally in large pipes due to Stoke's law effects, especially at elbows changing the direction of flow where the particles impinge against the pipe wall and are temporarily halted. Wax precipitation often results in the formation of sub-micron wax spherical particles that also settle under the influence of gravity. Although paraffin waxes have specific gravities around 0.8 to 0.85, field waxes have higher specific gravities, usually higher than 0.9, because they usually co-precipitate with asphaltenes and resins, if present. Hence, in oils that contain asphaltenes and resins, precipitating waxes do settle by gravity. It has been shown that asphaltenes and resins are considered responsible for causing the formation of amorphous spherical wax crystal particles rather than wax needle crystals. Both flocculated asphaltene particles and crystallized wax particles agglomerate to form very large micron-level particles whose molecular weights run in the hundreds of thousands or millions. These large particles settle fairly quickly in storage systems. This paper presents a modeling methodology for the simulation of sedimentation of asphaltene and wax particles in both onshore and offshore storage systems. The asphaltene and wax particle size distribution is usually available from microscopic observations, filtration, and thermodynamic models. The sedimentation calculation is done by assuming that the particles have settled and are at gravimetric equilibrium. Two examples are presented: one 1,000,000-barrel FPSO case and one 250,000-barrel oil storage tank case. Both the FPSO and the tank had lost a substantial fraction of their capacity due to accumulation of asphaltene and wax sludge.

In oil fields, the reservoir rock consists mainly of quartz, clays, ferric hydroxide or aluminium hydroxide. Thus, the oil retained in the reservoir rock is in contact with various mineral surface types. Illite and kaolinite are the main clays present in the rock. Such clays have higher surface areas and surface charges and play an important role in the oil uptake process. Many works have shown that asphaltenes, which are the crude oil polar component, adsorb preferentially on clay surfaces. In addition, in crude oil, asphaltenes aggregation or phase separation may occur under unfavourable solvent conditions. It should be emphasised that asphaltenes are the crude oil fraction, which is insoluble in heptane and soluble in aromatic solvents like toluene. The aim of the present work is to throw light on the mechanism by which asphaltene molecules interact with clay surface. The asphaltenes were adsorbed from water-saturated toluene onto kaolinite and montmorillonite clays. Further, in ...

The deposition of asphaltene, wax, hydrates, scale, and even transfer of sands in oil wells and pipelines are serious problems that cause production interruptions and lead to substantial economic losses. The present study opens a new window for solving this unresolved problem. Accordingly, an improved Eu-lerian deposition model that incorporates various mechanisms of particle transport and deposition (e.g., molecular and turbulent diffusion, turbophoresis, thermophoresis, and surface roughness) was extended to predict solid deposition in oil wells. In this paper, to make it possible to predict deposition in inclined and horizontal pipes, the model was modified to include the gravitational settling effect. Moreover, using this model, a new method was proposed to determine the particle size distribution and particle floccu-lation function. It was first validated by predicting particle deposition in turbulent airflow and showed very good agreement with a wide range of published observation data. Then the model was used for predicting the thickness profile of asphaltene deposition in two laminar flow capillary tube experiments reported in the literature. This model, for the first time, has predicted asphaltene deposition profiles with high accuracy, especially without the use of empirical parameters. The predictions of this model are as accurate as particle tracking methods but at much lower computational costs. This study demonstrates that under certain conditions in laminar flow, deposition is dominated by gravitational settling, while it has been hypothesized previously that asphaltene deposition predominantly occurs by diffusion. The results reveal that particle size distribution plays a vital role in asphaltene deposition modeling. The findings of this study can help for a better understanding of the effective mechanisms of asphaltene deposition. This is the most versatile theory that can be adapted with various flow conditions. Since this approach does not depend on the solid type, it can be similarly applied to predict the behavior of other solid-fluid flow assurances in oil and gas facilities. Modeling the solid solution and multi-solid phase behavior are other capabilities of the developed methodology. The high accuracy of this approach and using minimum adjustable parameters offer many avenues for future development to evaluate particle deposition in real field applications.

Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlat...

TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract At some thermodynamic conditions, asphaltenes flocculate into larger, almost spherical particles that have a specific gravity of 1.05 to 1.10. Work is cited here that indicates that asphaltene stable colloids exist in oil as very minute particles and that their pre-flocculation sizes are in the range of about 10 to 15 Å. This corresponds to 334 and 1,128 molecular weight respectively, assuming asphaltene spherical colloids and an experimentally determined asphaltene density of 1.06 g/cm 3. The reason for this high specific gravity of asphaltene particles compared to the rest of the molecules of oils is that they consist mostly of asphaltenes and resins, the heaviest constituents of oils. Roughly, resins have specific gravities of 0.95 to 1.0 and asphaltenes 1.1 to 1.2. Because of their high specific gravity asphaltene particles settle by the force of gravity in storage systems where the convection currents and shear forces are minimal. Some of these particles are large enough to overcome the convection currents and shear forces and settle in large separators and occasionally in large pipes due to Stoke's law effects, especially at elbows changing the direction of flow where the particles impinge against the pipe wall and are temporarily halted. Wax precipitation often results in the formation of sub-micron wax spherical particles that also settle under the influence of gravity. Although paraffin waxes have specific gravities around 0.8 to 0.85, field waxes have higher specific gravities, usually higher than 0.9, because they usually co-precipitate with asphaltenes and resins, if present. Hence, in oils that contain asphaltenes and resins, precipitating waxes do settle by gravity. It has been shown that asphaltenes and resins are considered responsible for causing the formation of amorphous spherical wax crystal particles rather than wax needle crystals. Both flocculated asphaltene particles and crystallized wax particles agglomerate to form very large micron-level particles whose molecular weights run in the hundreds of thousands or millions. These large particles settle fairly quickly in storage systems. This paper presents a modeling methodology for the simulation of sedimentation of asphaltene and wax particles in both onshore and offshore storage systems. The asphaltene and wax particle size distribution is usually available from microscopic observations, filtration, and thermodynamic models. The sedimentation calculation is done by assuming that the particles have settled and are at gravimetric equilibrium. Two examples are presented: one 1,000,000-barrel FPSO case and one 250,000-barrel oil storage tank case. Both the FPSO and the tank had lost a substantial fraction of their capacity due to accumulation of asphaltene and wax sludge.