Challenges Inherent in the Development of Predictive Deposition Tools for Asphaltene Containing Hydrocarbon Fluids

The correlation and prediction of deposit formation are at the core of flow assurance, risk assessment, and other reservoir fluid management issues and are equally important for heavy oil or bitumen partitioning and upgrading. Asphaltene deposition in particular is a key topic in both sectors. Hydrocarbons from condensate-rich reservoir fluids to bitumen + diluent mixtures share constituents, from asphaltenes and resins to pentane, and can all be classified as asymmetric from a phase behavior perspective. The phase dia-grams for these asymmetric fluids are characterized by zone of four-phase behavior surrounded by three-phase and two-phase regions in both pressure-composition at constant temperature, and pressure-temperature at constant composition diagrams. Adherent asphaltenic solid and liquid deposits only arise within some multiphase zones. Zones such as the SL1, SL1V, L1L2V, and L1L2 are prone to the production of adherent asphaltenic deposits particularly when combined with intermittent or laminar flow. By incorporating incomplete approaches prevalent in both sectors into qualitative four component phase diagrams, one can illustrate key aspects of the phase diagrams for the entire range of fluids, as well as the challenges faced with respect to the prediction of specific phase behaviors. In this article we present and illustrate some of these challenges and propose a path toward their resolution.     

Dispersed Phases and Dispersed Phase Deposition Issues Arising in Asphaltene Rich Hydrocarbon Fluids

Our interest in the phase behavior of asymmetric, industrial organic fluids focuses on understanding the impact of phase behavior, particularly solid phase behavior, on flow assurance and other reservoir fluid management and production issues, as well as on heavy oil partitioning processes in upgrading operations. Recent developments in X-ray view cell technology allow us to examine the phase behavior of fluids containing large mass fractions of asphaltenes, and dispersed organic and inorganic solids, in a routine manner. Over the past three years we have been preparing detailed phase behavior maps, including phase densities, for the model system Athabasca Bitumen Vacuum Bottoms (ABVB), a 525+ °C fraction containing 32 wt% pentane asphaltenes + pentane, heptane and dodecane using a variable volume X-ray view-cell. The X-ray view-cell experimental program focused on the temperature range, 100 to 340°C, and the pressure range, 0.1 to 30 MPa. The mixtures exhibit complex but reversible multiphase behaviors. Over much of the phase space solids, if present, remain dispersed. Over a narrow range of conditions the solids tend to settle. In addition, adherent deposits, including solids and viscous liquids, are observed at temperatures less than 200°C over a broad range of conditions.     

Investigation of Asphaltene Precipitation Process for Kuwaiti Reservoir

Abstract

As part of an Enhanced Oil Recovery (EOR) research program, Asphalting precipitation processes were investigated for a Kuwaiti dead oil sample using different hydrocarbons and carbon dioxide as precipitants at the ambient and high pressure of 3000 psig conditions. The hydrocarbons used as precipitants were ethane (C2), propane (C3), butane (C4), normal pentane (n-C5), normal hexane (n-C6), and normal heptane (n-C7). The equipment used for this investigation was a mercury-free, variable volume, fully visual JEFRI-DBR PVT system with laser light scattering. The minimum critical value of precipitants concentration for the oil sample has been identified at the ambient and high-pressure conditions for each precipitant. Our investigation has revealed that for this oil sample the most powerful asphaltene precipitant were CO₂ followed by C2, C3, C4, n-C5, n-C6, and n-C7. Moreover, the effect of pressure and temperature on the asphaltene precipitation has been investigated experimentally for CO₂, n-C5, n-C6, and n-C7. The precipitation and redissolution of asphaltene upon the addition and removal of CO₂ and light alkanes (C2–C4), at 3000 psig and ambient temperatures, have shown evidence of reversibility of asphaltene precipitation. A comprehensive fluid characterization analysis for the oil sample has been performed including, physical properties of crude oil, compositional, molecular weight (Mw), and SARA analyses. Advanced analytical techniques such as 1H and 13C NMR and IR spectrometers have been utilized to investigate the molecular structure of the asphaltene for this sample. It was concluded that the asphaltene molecules for this oil contain 120 total aromatic carbons with 42 aromatic rings, 114 naphthenic rings, and 5–7 sets of condensed aromatic rings.     

A Thermodynamic Model for the Prediction of Asphaltene Precipitation

Abstract

Asphaltene precipitation in reservoirs, wells, and facilities can have a severe and detrimental impact on the oil production. Due to the extreme chemical complexity of the asphaltene and crude oil and the lack of comprehensive experimental data, the modeling of asphaltene precipitation in crude oil remains as a challenging task. In this article, a compositional thermodynamic model was developed to predict asphaltene precipitation conditions. The proposed model is based on a cubic equation of state with an additional term to describe the association of asphaltene molecules. Extensive testing against the literature data, including asphaltene precipitation from crude oil and solvent injection systems, concludes that the proposed model provides reasonable predictive results.     

Experimental investigation of asphaltene deposition mechanism during oil flow in core samples

Asphaltene deposition is an issue that has received much attention since it has been shown to be the cause of major production problems in enhanced oil recovery processes. Asphaltenes are heavy oil components which, under certain conditions, precipitate and the solid phase they form may deposit in the porous media of the oil reservoir. All proposed remediation techniques have proven costly and not highly effective, so prevention becomes the only way to counteract the problem. Revelation of the deposition mechanism and determination of the parameters they affect it are necessary in order to devise reliable prevention strategies. In this work, an experimental effort is made to investigate the deposition process in core samples, under simulant and realistic flow conditions. The main experimental tools utilized for this purpose are permeability measurements, analysis of asphaltene concentration, pore structure characterization techniques and Soxhlet extraction for the determination of the deposited asphaltenes. Both dead and reservoir oils are used as well as cores of various permeabilities and pore structure characteristics.     

MOLECULAR SIZE AND STRUCTURE OF ASPHALTENES

Fluorescence depolarization measurements are used to determine the size of asphaltene molecules and of model compounds for comparison. Mean molecular weights of 750 amu have been found for petroleum asphaltenes. A strong correlation is established between the size of fused rings in asphaltene molecules and the overall size of these molecules, showing that asphaltenes have one or perhaps two fused ring systems per molecule. Coal asphaltene molecules are found to be much smaller than petroleum asphaltenes.     

Effects of Catalyst Properties on Asphaltenes Composition During Hydrotreating of Heavy Oils

Three NiMo commercial catalysts were used for carrying out hydrotreating (HDT) experiments in a high-pressure pilot plant. Maya crude oil was employed as HDT feed. All hydrotreated products and their corresponding precipitated asphaltenes fractions were characterized by elemental analysis and metals contents. Extraction of asphaltenes was carried out according to the method described in ASTM D-3279. It was observed from our characterization results that while nitrogen and metals content in asphaltenes increase sulfur decrease as the reaction temperature is increased. This different behavior was attributed to the localization of each heteroatom in the asphaltene molecule. Pore size of catalysts showed the major influence on hydrotreated product asphaltenes composition.     

A new technique for treatment of permeability damage due to asphaltene deposition using laser technology

This study proposes a new technique for cleaning deposited asphaltenes using laser energy. Two series of experiments were carried out to achieve this objective. In the first one, one-inch column of bitumen mixed with limestone was placed above powdered limestone column in a flow cell. In the second series of experiments, actual consolidated limestone cores were subjected to flow of asphaltenic crude oil to simulate the damage process (i.e. permeability reduction). Both unconsolidated and consolidated limestone samples were subjected to a laser energy using laboratory diode modules at various laser intensity and treatment time intervals.Experimental results indicated that exposure of the above-mentioned permeability damaged limestone samples to laser energy caused asphaltene disruption and resulted in recovery of damaged permeability. The increase of laser intensity increased the recovered permeability and the optimum time duration is measured to be 1 h at laser intensity of 19 mW/h. Simultaneous pumping is required during the laser treatment to avoid the re-precipitation of the disrupted asphaltene.     

Investigation of supercritical carbon dioxide, aspheltenic crude oil, and formation brine interactions in carbonate formations

Asphaltene precipitation and rock dissolution can significantly hinder the success of carbon dioxide flooding of asphaltenic crude oil in carbonate heterogeneous formations. It is essential during CO₂ flooding when both processes exist to study separately the effect of each phenomenon on the flooding process. Ten core flooding experiments under similar reservoir conditions of 4000 psia pressure and 250 °F temperature were conducted to evaluate each phenomenon separately. Actual rock cores representing different areas of carbonate oil field saturated with actual fluids of filtrated brine and asphaltenic crude oil were used to evaluate the interaction between supercritical (SC)-CO₂, carbonate rock, and its contained fluid. Asphaltene content of the produced crude oil, water and mineralogical rock analyses, and scanning electron microscopic (SEM) photos of rock pores were performed to evaluate the effect of supercritical (SC)-CO₂ flood on the permeability and mineralogical variation characteristics of the limestone cores. Results indicated that calcite dissolution and/or precipitation is the major reason for permeability improvement and/or impairment. It is also proven that the amount of permeability damage depends on the fabric of the rocks, salinity of the brine, and initial core permeability. The results also indicated that CO₂ injection in fresh water saturated carbonate rock led to complete collapse of that rock. It is recommended that fluid assessment should be conducted to the different areas of the field.     

Kinetics of CO2-induced asphaltene precipitation from various Saskatchewan crude oils during CO2 miscible flooding

A molar CO₂ programmed titration technique was used to evaluate the kinetics of CO₂-induced asphaltene precipitation from three Saskatchewan crude oils (namely Steelman, 12-25-6-14w2 and D8-12-6-14w2) under isothermal (in the range of 300–338 K) and isobaric (at 17.2 MPa) reservoir conditions in a solids detection system (SDS) consisting essentially of a mercury-free, variable volume, fully visual, JEFRI PVT cell. The results show that the rate of asphaltene precipitation depends on, both, the asphaltene and CO₂ contents of the oil. This work represents the first attempt at obtaining kinetic data for asphaltene precipitation from crude oil without any pretreatment of the oil as well as formulating a kinetic model that fits the data. Different values for the reaction order (m) of asphaltene, and the reaction order (n) for CO₂ were obtained for the same oil at different temperatures. This shows that the mechanism for CO₂-induced asphaltene precipitation was temperature dependent. Also, the values of n for all the oils at all the temperatures were much larger than the corresponding values for m. This shows that asphaltene precipitation is extremely more sensitive to CO₂ content than asphaltene content, even though the contribution from asphaltene content in the oil cannot be ignored. The large overall reaction order (m+n>4) also provides the experimental evidence to confirm that asphaltene precipitation is not an elementary process.     

Investigation of the asphaltene deposition along the flow of the oil in tubing: Experimental study and a parametric analysis

In this work, a novel experimental setup was designed and utilized to carry out the n-alkane induced asphaltenes for understanding the kinetics of deposition and also effects of oil velocity, oil-precipitant volumetric dilution ratio, and temperature on the rate of asphaltene deposition. As the deposited layer of asphaltenes makes it difficult for the flow of oil along the tube, measurement of the pressure drop across the tube section of setup enabled the measurement of the amount and extent of deposition process at desired condition. The experimental results revealed that increasing the velocity of fluid across the pipe dominance the shear force on asphaltene deposit and cause remobilization of part of the deposit into the flowing fluid in contrary to oil-precipitant ratio, where deposition rate is enhanced with increasing DR ratio. The results of this work elucidate some less-addressed shadows of dynamics of flow blockage in pipelines and could create a better framework for conducting forthcoming experiments     

Experimental and modeling asphaltene precipitation in presence of DBSA using PC-SAFT EOS

Asphaltene precipitation and subsequent deposition in production tubing and topside facilities present significant cost penalties to crude oil production. Therefore, it is highly desirable to predict their phase behavior and the efficiency of dispersants in preventing or delaying deposition. Very few studies have been carried out on the molecular interactions between asphaltenes and different dispersants. As a result, the mechanisms by which dispersants stabilize asphaltenes are still open to discussion. The authors introduced a new method to characterize asphaltenes in perturbed chain statistical association fluid theory equation of state (EOS; perturbed-chain statistical association fluid theory EOS [PC-SAFT-EOS]) and correctly model the effect of dodecyl benzene sulfonic acid (DBSA) dispersant on the thermodynamic behavior of asphaltenes. Using the filtration method the effect of the ionic dispersant (DBSA) on asphaltene precipitation for different concentrations of n-heptane was measured experimentally, then modeled through PC-SAFT EOS. In the approach only the hard-chain and the dispersion terms are taken into consideration, and PC-SAFT parameters were calculated based on Gonzales et al. (2007 Gonzalez, D. L., Hirasaki, G. J., Creek, J., and Chapman, W. G. (2007). Modeling of asphaltene precipitation due to changes in composition using the perturbed chain statistical associating fluid theory equation of state. Energy Fuels 21:1231–1242.[Crossref], [Web of Science ®] , [Google Scholar]) based on molecular weight (Mw) and aromaticity factor (γ). Additionally, the model could correctly predict the amount of asphaltene precipitation upon addition of DBSA dispersant.     

Molecular Weight Measurement of UG8 Asphaltene Using APCI Mass Spectroscopy

Abstract

Asphaltene molecular weight has been a controversial issue in the past several decades and continues on nowadays. From industrial application point of view, asphaltene molecular weight is important for setting up a heavy oil refining strategy so that the process is efficient and economically viable. If the measured average molecular weight of asphaltene is high and is the true molecular weight, then substantial amount of energy will be needed, in order to break the molecule into light products during refining process. This is likely not an economical option. On the other, if the measured high molecular weight is due to self-association and the true molecular weight is low (e.g., less than 1500 Da), it will be energetically attractive to refiners to develop heavy oil cracking technology. Vapor pressure osmometry (VPO) has been routinely used for measuring molecular weight. However, it measures the apparent molecular weight and is likely not the true molecular weight. In order to unambiguously measure the molecular weight, it is necessary to develop a convincing technology and a reliable experimental procedure that allows one to measure the molecular weight accurately and consistently. We chose the Atmospheric Pressure Chemical Ionization (APCI) technique and Atmospheric Pressure Photo Ionization (APPI) to measure UG8 asphaltene. Both APCI and APPI have mild ionization processes and have been applied to many unstable drug compounds such as proteins and peptides with reliable outcomes. In addition, we measured the sample on two APPI instruments to compare the results. We also demonstrated how one can choose wrong set of operating parameters and lead to erroneous results. The relevant parameters for APCI and APPI are temperature, voltage, and sample concentration. We chose 0.01 mg/mL as the concentration, much below any known critical aggregation concentration. As for temperature and ionization voltage, we varied systematically varied (T = 300–600°C; V = 30–150 V) in order to demonstrate the consistency of the methods and how one can easily make mistake. Through these measurements, an average molecular weight of 400 to 900 Da was obtained for UG8 asphaltene.