Onset Of Asphaltene Precipitation Research Articles

Heterogeneity of Asphaltene Deposits on Gold Surfaces in Organic Phase Using Atomic Force Microscopy

Atomic force microscopy (AFM) was used to measure the heterogeneity of asphaltenes adsorbed on gold for pentane-to-oil ratios (S/O) ranging from 0 to 0.5. Both adsorption of asphaltenes and AFM measurements were conducted in the same solvent mixture of toluene and pentane. The averaged approach and retraction heights of the deposited asphaltene material increased from 2 nm on washed surfaces to 8 nm for S/O = 0.43. The average adhesion forces during retraction of the AFM tip were greater than zero for S/O > 0.2. Repetition of the approach and retraction measurements at different locations on gold substrates showed that the deposited asphaltene aggregates are heterogeneous in height and elasticity. The extent of the heterogeneity is more evident at the onset of asphaltene precipitation (S/O = 0.43).

PC-SAFT characterization of crude oils and modeling of asphaltene phase behavior

Asphaltenes are the heaviest and most polarizable components of crude oil. The phase behavior of these polydisperse components is important in both the upstream and downstream processing of crude oil because of their potential to precipitate, deposit and plug pipelines and production equipment. Predicting flow assurance issues caused by asphaltenes requires the ability to model the phase behavior of asphaltenes as a function of temperature, pressure, and composition. In this work we present a detailed procedure to characterize crude oil and plot asphaltene phase envelope, using the Perturbed Chain form of the Statistical Associating Fluid Theory (PC-SAFT). This work also demonstrates that the proposed procedure can model the asphaltene thermodynamic phase behavior better than using a cubic equation of state typically used in the industry, even with compositional data as low as C9+.The results obtained with the proposed characterization method show a remarkable matching with the experimental data points for both the bubble point and asphaltene precipitation onset curves. A wide range of temperatures, pressures and gas injection percentages have been tested. In this work, the concept of lower asphaltene onset pressure is also clarified and a new representation of asphaltene phase plot is presented. The results obtained in this work are very promising in providing better tools to model asphaltene phase behavior.

Inhibition of Asphaltene Precipitation by TiO2, SiO2, and ZrO2 Nanofluids

Asphaltene precipitation causes several problems during crude oil production, transportation, and refinery processes. Therefore, finding an inhibitor to prevent or delay asphaltene precipitation is of paramount importance. In this work, effects of TiO2, ZrO2, and SiO2 fine nanoparticles in organic-based nanofluids have been investigated to study their potential for stabilizing asphaltene particles in oil. To this end, polarized light microscopy has been applied to determine the onset of asphaltene precipitation by titration of dead oil samples from Iranian crude oil reservoirs with n-heptane in the presence of nanofluids. Results show that rutile (TiO2) fine nanoparticles can effectively enhance the asphaltene stability in acidic conditions and act inversely in basic conditions. It was found that the required amount of n-heptane for destabilizing the colloidal asphaltene is considerably higher in presence of TiO2 nanofluids at pH below 4. The FTIR spectroscopy indicates changes in n-heptane insoluble asph...

Looking for a Model Solvent to Disperse Asphaltenes

Petroleum could be seen as a system of asphaltenes dispersed in other petroleum components. The petroleum components excluding the asphaltenes are referred to in this paper as Petroleum Medium that Disperses the Asphaltenes – PMDA). This paper proposes a methodology to determine solubility parameter of the PMDA by identifying a model solvent which, when added to the petroleum, does not affect the asphaltenes phase behavior. In order to achieve such objective the asphaltenes precipitation onset (PO) of the petroleum was determined, followed by the identification of a solvent mixture which, when added to the petroleum, does not change the PO. The solubility parameter () of the PMDA was assumed equal to the solubility parameter of the identified solvent mixture.

Study of water-in-oil thin liquid films: Implications for the stability of petroleum emulsions

The lifetimes, thicknesses, and thinning rates of water-in-diluted bitumen emulsion thin liquid films depend on solvent-to-bitumen ratio (S/B) and on the aromaticity of the solvent used. For aliphatic solvents, the emulsion film properties change abruptly at a well-defined dilution coinciding with the onset of asphaltene precipitation and previously observed critical S/B at which bulk emulsion properties change dramatically. Microscopic observations reveal that above critical S/B, water/oil interfaces become rigid and small asphaltene aggregates are formed. After some ageing time, larger secondary precipitates appear in the film. When the bitumen was diluted above critical S/B and precipitated asphaltenes were removed by centrifugation, we observed a significant increase in the equilibrium film thickness and stability. This counterintuitive finding is possibly due to a build-up of a multilayer at the water/oil interface, driven by poor solubility of asphaltenes in aliphatic solvent. The experiments were performed using the microinterferometric thin liquid film technique. The films were created from Athabasca bitumen diluted with mixtures of toluene and heptane at various toluene to heptane and solvent to bitumen ratios.

Prediction of Asphaltene Precipitation: Learning from Data at Different Conditions

Asphaltene precipitation affects enhanced oil recovery processes through the mechanism of wettability alteration and blockage. Asphaltene precipitation is very sensitive to the reservoir conditions and fluid properties, such as pressure, temperature, dilution ratio, and injected fluid molecular weight. A Bayesian belief network (BBN) was used in this study as an artificial intelligence modeling tool to investigate the effect of different variables/parameters on asphaltene precipitation. The predicted results from the BBN model were compared to the experimental precipitation data obtained using high-resolution images captured in a high-pressure cell and processed by image analysis software. The cell accessories facilitate in situ visual monitoring of nuclei growth of asphaltene at high pressures and specified temperatures. The average relative absolute deviation between the model predictions and the experimental data was found to be less than 4.6%. Burst of nucleation or the onset of asphaltene precipitation was also determined at different conditions directly by the developed BBN model. A comparison between the prediction of this model and the alternatives showed that the BBN model predicts asphaltene precipitation more accurately and covers a wider range of affected variables/parameters.

Composition of Asphaltene Solvate Shell at Precipitation Onset Conditions and Estimation of Average Aggregate Sizes in Model Oils

Macroscopic properties of petroleum disperse systems are functions of its particle size. Asphaltene particles in model oils are in fact building agents. Compositional changes of disperse medium have an effect on the internal structure of the dispersed system. Optical methods are informative enough for analysis of structural evolutionary processes. Near-infrared (NIR) spectroscopy was used to determine asphaltene precipitation onset conditions in model oils (asphaltenes were dissolved in binary solvent: toluene and n-alkane precipitant n-hexane/n-heptane). Asphaltene precipitation onset was determined as a point where the deviation from Beer’s law takes place. Solvate shells of asphaltenes in binary solvents are formed according to differences between intermolecular interaction potentials of components of the model oil. The model of non-uniform distribution of components in solvate shells of asphaltene aggregates at the moment of aggregation stability loss (first stage of precipitation onset) is proposed. On the basis of experimentally determined asphaltene precipitation onset conditions, average aggregate sizes in toluene solutions, set of assumptions concerning geometry of solvent and precipitant molecules, and interaction energy of molecule pairs, the proposed model allows for estimation of the precipitant fraction threshold value in solvate shells of asphaltene aggregates at the moment of stability loss. Polarization of fluorescence was used for the determination of the concentration dependence of average sizes of aspahltene aggregates in toluene solution. The linear aggregation model was used for characterization of asphaltene solutions in toluene; the fraction of n-mers was determined. The concentration dependence of the asphaltene aggregation rate constant was calculated within this model.

Determination of the Onset of Asphaltene Precipitation by Visible Ultraviolet Spectrometry and Spectrofluorimetry

Asphaltene deposition is a problem for the petroleum industry, affecting the production, transport, and storage of crude oil. The aim of this work is to develop and compare different methods to determine asphaltene precipitation. Two asphaltene fractions, one extracted from a Brazilian crude oil sample and the other from petroleum distillation residue, were evaluated by using model systems constituted of toluene/n-heptane in different compositions, using visible ultraviolet spectrometry and spectrofluorimetry. The results of the precipitation tests carried out by these two methods agreed, indicating they are effective to analyze asphaltene deposition and the performance of chemicals as asphaltene stabilizers.

Measurement and Modeling of Asphaltene Precipitation from Crude Oil Blends

A previously developed regular solution model was adapted to predict the onset and amount of asphaltene precipitation from crude oil blends diluted with pure n-alkanes or a mixture of toluene and n-heptane. Tests were conducted on nine different crude oils, a gas oil, and their blends. Oils and blends were characterized in terms of SARA (saturates, aromatics, resins, and asphaltenes) fractions. The mass fraction of each SARA fraction in the blends was confirmed as a weight average of the respective fraction in constituent oils. Asphaltenes were subdivided into fractions based on the gamma function to account for the distribution of aggregates resulting from self-association. To model the asphaltene onset and yield, liquid−liquid equilibrium was assumed between a heavy (asphaltenic) and a light (nonasphaltenic) phase. The distribution of asphaltenes in unblended crude oils was determined by fitting its asphaltene yield data when diluted with n-heptane. The fitting parameter in the model was the average aggregation number of asphaltenes in the source oils. Two approaches were tested to calculate the distribution of asphaltenes in crude oil blends. In the first approach, asphaltenes were assumed to interact, and the final molar mass distribution was determined from gamma function using the average aggregation number of constituent oils. In the second approach, no interaction was assumed, and the final distribution was calculated as a sum of the individual distributions. It was found that the best predictions of the onset and yield data were obtained by using the second approach. The mass fraction of n-heptane required to initiate precipitation was predicted with an average absolute deviation of 0.53% or less in all cases.

Development of a General Method for Modeling Asphaltene Stability

Asphaltenes constitute a potential problem in deep-water production because of their tendency to precipitate and deposit. A universal model to predict the stability of these species, under different conditions, is desirable to identify potential asphaltene problems. In our study, we present important advances in developing a general method to model asphaltene stability in oil. The perturbed chain-statistical associating fluid theory equation of state (PC-SAFT EoS), which has been previously validated, has been used to generate simulation data for a model oil containing different asphaltene precipitants. When dimensionless parameters are defined, the equilibrium curves of different multicomponent mixtures collapse onto one single curve. Universal plots for the bubble point and the onset of asphaltene precipitation have been obtained, which are in excellent agreement with results obtained from simulations. Extension of this model to mixtures containing dissolved gases, such as methane, CO2, and ethane, is also included. In the present work, we show a derivation of a new mixing rule for solubility parameters of mixtures containing liquids and dissolved gases. The agreement with simulation results and refractive index measurements is good. Results obtained in this work are very promising in providing new tools to model asphaltene stability under reservoir conditions.

Solution Behavior of Naphthenic Acids and Its Effect on the Asphaltenes Precipitation Onset

Naphthenic acids represent a subfraction of the crude oil resins that contains predominantly carboxylic acids with saturated cyclic structures and corresponds to a complex mixture of compounds. The naphthenic acids can cause deposition problems. These compounds however also play an important role in some phenomena occurring, and then separation from crude oil would improve oil quality during the production. In this contribution, some aspects of the solution behavior of naphthenic acids are presented. It was observed that these compounds form stable liquid mixtures with organic solvents in a wide range of solubility parameters. When added to partially soluble liquid mixtures, such as n-heptane/methanol, they improve the mutual solubility of these liquids, increasing the solubility domain and partition into both liquid phases. The precipitation onset for asphaltenes dissolved in toluene titrated with n-heptane was increased by the addition of naphthenic acids, indicating that these compounds contribute to the solubilization of asphaltenes representing a “good solvent” for this fraction. Applying the polymer solutions to the asphaltenes dissolved in liquid mixtures, treating the naphthenic acids as pure pseudo-components, and assuming that asphaltenes precipitation onset occurs at a particular solvent composition corresponding to a “critical solubility parameter” value from 20 to 23 MPa1/2 were obtained for the naphthenic acids that are in good agreement to those obtained by differential scanning calorimetry (DSC).

Prediction of asphaltene precipitation using non-isothermal compositional network model

In this paper a comprehensive flow model which incorporates compositional and non-isothermal effects is proposed to investigate asphaltene precipitation onset conditions in advanced well completions. The focus is on precipitation induced by pressure and temperature conditions, particularly in flow restrictions used in wells to delay unwanted break through of water/gas. A network model is used with a non-isothermal black oil fluid model to predict the distribution of pressure, temperature, flow rate and phase fractions in all components of the well completion. The network geometry consists of a production tubing (or liner) and an annulus between the reservoir and the tubing. This geometry will allow for flow between the annulus and the tubing through inflow control devices which are commonly used for zonal control. An asphaltene precipitation envelope is used to identify locations in the well completion at risk. Subsequently, a fully compositional and non-isothermal model is invoked at these locations. This detailed model uses a Finite Difference representation of conservation of mass, energy and momentum. Furthermore, it uses an isenthalpic pseudo-three-phase equilibrium model to predict if asphaltene precipitation actually will occur inside the restriction. A case study is presented in which the proposed model was successfully used to predict physical flow parameters and asphaltene onset conditions. It was found that asphaltene precipitation may occur in flow restriction due to large pressure drop. Furthermore, it was found that the use of isothermal modeling to predict asphaltene precipitation may lead to underestimation of the precipitation. It is concluded that the details of the well completion must be represented in the flow model since pressure and temperature may vary non-monotonically from toe to heel in advanced well completions.

Developing of Scaling Equation with Function of Pressure to Determine Onset of Asphaltene Precipitation

Developing of Scaling Equation with Function of Pressure to Determine Onset of Asphaltene Precipitation

Applying the PR-EOS to Predict the Onset of Asphaltene Precipitation from n-Alkane Diluted Bitumens

Asphaltenes are the n-pentane or n-heptane insoluble fractions of crude oil that remain in solution under reservoir temperature and pressure conditions. They are destabilized and start to precipitate when the pressure, temperature and/or composition changes occur during primary production. The precipitated asphaltene particles will then grow in size and may start to deposit onto the production string and/or flowlines, causing operational problems. In this paper, a combination of the modified Peng-Robinson (PR) EOS and regular solution theory is used to estimate the onset of asphaltene precipitation of some oils. The PR EOS was modified using contribution methods for the asphaltenes which are assumed to be polymeric-like compounds consisting of aggregates of monodisperse asphaltene monomers. The modified EOS with the Peneloux correction was used to estimate the molar volumes and solubility parameter of the four solubility classes (Saturates, Aromatics, Resins, Asphaltenes) of bitumens. The predicted parameter of EOS was used to determine the onset of asphaltene precipitation from bitumen upon the addition of heptane and predictions were compared with measured onsets. Liquid-Liquid equilibrium was assumed between an oil phase and an asphaltene-ri ch phase. The asphaltene were divided into several pseudo components based on the Schultz-Zimm distribution function. Application of this model will help operators to better forecast the onset of asphaltene precipitation as it relates to flow rate history of the well and the pace of plugging induced by asphaltenes, and thus better plan remedial measures. The agreement between the predicted and measured onsets is very good.

Modeling of Asphaltene Precipitation Due to Changes in Composition Using the Perturbed Chain Statistical Associating Fluid Theory Equation of State

Asphaltene precipitation and deposition adversely affect production assurance and are key risk factors in assessing difficult environments such as deepwater. Deposition in the near well bore regions and production tubulars implies high intervention and remediation costs. Prediction of asphaltene precipitation onset represents a challenge for the flow assurance area. The applicability of the PC-SAFT equation of state model to predict asphaltene onset of the precipitation in live oils is demonstrated by studying representative examples from field experiences with asphaltene problems during production. These examples not only validate the proposed model but also confirm the theory that asphaltene phase behavior can be explained based only on molecular size and van der Waals interactions. The PC-SAFT equation of state estimates also properties such as densities and bubble points of live oil systems using a minimum number of real components and “realistic” pseudocomponents. The amount and composition of the asphaltene precipitated phase is also determined as part of the equilibrium calculations. This paper presents experimental observations and simulation results at reservoir conditions using the PC-SAFT equation of state on the effect of compositional changes in live oils caused by two common processes in the oil industry: oil-based-mud (OBM) contamination and reinjection of associated gas. In the first case, the downhole oil samples can be contaminated with OBM, causing laboratory measurements of the bubble point and asphaltene precipitation to be different from the reservoir fluid. In the second case, the reinjection of gas into the field increases the gas−oil-ratio (GOR) of the oil. The addition of gas into the oil can cause asphaltene precipitation and deposition due to the increase of light components that reduces asphaltene solubility. Asphaltenes in this example are treated as both monodisperse and polydisperse pseudocomponents. From the obtained results, it can be concluded that the live oil modeled using the PC-SAFT equation of state properly predicts the asphaltene phase behavior under these compositional changes. The PC-SAFT equation of state model is a commercially available, proven tool.

A Shortcut Application of a Flory‐Like Model to Asphaltene Precipitation

A model, previously developed to determine the asphaltene precipitation onset, considered that asphaltene separation is ruled by the solvent quality of the surrounding media. Here, it is shown that it is equivalent to Flory‐Huggins model, when it is hypothesized that the asphaltene concentration is always in the instability range. With this, the controversy on the use of a concentration‐dependent model to describe a phenomenon that is practically independent of concentration is by‐passed. Moreover, improvements of the model are presented, together with sensitivity analysis with respect to its parameters. Two field case applications are reported, showing that the model gives a reasonable fit.

Simplifying the Thermodynamic Modeling of Asphaltenes in Upstream Operations

The development of a thermodynamic model to predict the onset of asphaltene precipitation is usually hindered by the complexity of the mixture under consideration. In an attempt to simplify asphaltene modeling, a model related to the Flory−Huggins theory had been previously proposed. The model is based on the fact that asphaltene stability depends upon the quality of the surrounding medium, expressed in terms of the solubility parameter. Moreover, the model only takes into account the first asphaltenes that come out of the solution. This allows the theoretical determination of one of the parameters starting from the concept of infinite dilution, as described in this work. This paper also presents a discussion about the optimal way of determining the parameters of the proposed model.

Asphaltenes Precipitation from Crude Oil and Hydrocarbon Media

The asphaltenes precipitation onset and the precipitation yield were determined for four different crude oil samples. The results confirm that crude oil samples presenting low precipitation onsets effectively present instability and depositional problems in field operations, whereas those with a high onset are stable and do not present separation or precipitation in production operations. It was also confirmed that, as reported in the literature, the onset increased and the amount of solids separated decreased with the molecular weight of the alkane used to induce the precipitation. The same methodology was extended to asphaltenes, resins, and asphaltenes/resins mixtures dissolved in toluene using n-heptane and the ethyl alcohol as nonsolvents to evaluate the influence of the resins fraction on asphaltenes stabilization. The results analyzed using the Hildebrand solubility parameter point out for asphaltenes and resins being a continuum or family of complex molecules with a variation in molecular weight and polarity rather than two fractions containing chemically different compounds. This observation seems to be corroborated by the FTIR results that show similar spectra for asphaltenes separated using different solvents and for the resins fraction.

A simplified thermodynamic modeling procedure for predicting asphaltene precipitation

In this work, a simplified thermodynamic modeling procedure for determination of the amount of asphaltene precipitation is presented. The onset of asphaltene precipitation in the presence of different solvents is predicted by applying the molecular solubility model. Since asphaltene molecular weight varies in different solvents, the molecular weight of asphaltene has been tuned by experimental data. The tuned molecular weight is used to predict the amount of precipitated asphaltene. The Flory–Huggins statistical thermodynamics theory is applied to derive the Gibbs free energy relationship. A necessary and sufficient condition is defined to minimize the Gibbs free energy relation. By solving the set of equations derived from the minimization, the weight percent of precipitated asphaltene has been determined. The advantage of this model is that one does not need to perform expensive and time consuming experiment in order to obtain molecular weight data. The other improvement of this model compared to the other models is the requirement of a minimum amount of experimental data to find the unknown parameters. It also has the advantage of obtaining solubility parameters through thermodynamics relationships rather than using the relation for regular solution when the asphaltene solution is a non-regular solution. The results of this model are in good agreement with the experimental data.

Prediction of Asphaltene Instability under Gas Injection with the PC-SAFT Equation of State

Proper prediction of the potential for asphaltene precipitation in deepwater reservoirs represents a challenge for the flow assurance area due to both high intervention costs in case of asphaltene problems and extreme conditions of pressure, temperature, and composition. The probability of asphaltene precipitation increases when light-oil gases are considered for miscible gas injection processes. In this work, the applicability of simple and recombined live oil models using the PC-SAFT equation of state to predict the onset of asphaltene precipitation is demonstrated by studying pressure depletion and gas injection (carbon dioxide (CO2), nitrogen (N2), methane, and ethane) in oil reservoirs. The recombined model input includes the SARA characterization, the oil compositional analysis, and the gas−oil ratio. The pure component PC-SAFT parameters are fitted to the saturated liquid density and vapor pressure data, and the oil/gas pseudocomponent parameters are estimated from molecular-weight-based correlations. The EOS asphaltene parameters are fitted to precipitation data from oil titration with n-alkanes at ambient conditions. When asphaltene experimental data are not available, the asphaltene parameters are tuned to data at reservoir conditions, and then the model is run in a predictive mode. The PC-SAFT model was found to be in qualitative agreement with experimental data for the precipitant/crude oil systems in this study. In the prediction of the asphaltene onset using the model live oil, the results indicate that the ethane and CO2 mass fraction concentrations required to produce asphaltene precipitation is greater than for methane at the same pressure. Simulation results using the recombined model show that N2 addition produces a high asphaltene precipitation effect even at low concentrations. The simulated phase envelope for liquid−liquid asphaltene phase separation shows asphaltene stability bounded by an upper critical solution temperature and a lower critical solution temperature. The approach demonstrates that only molecular size and van der Waals interactions can explain laboratory and field observations of asphaltene phase behavior.