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Asphaltene precipitation

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Asphaltene precipitation is caused by a number of factors including changes in pressure, temperature, and composition. The two most prevalent causes of asphaltene precipitation in the reservoir are decreasing pressure and mixing of oil with injected solvent in improved oil recovery (IOR) processes. Drilling, completion, acid stimulation, and hydraulic fracturing activities can also induce precipitation in the near-wellbore region. This page focuses on field and laboratory observations associated with asphaltene precipitation during primary depletion and IOR gas injection, along with the experimental measurements used for asphaltene precipitation.

Aphaltene precipitation during primary depletion

In normal pressure depletion, reservoirs that experience asphaltene precipitation usually have the following characteristics[1]:

  • Fluid in place is light to medium oil with small asphaltene content.
  • Initial reservoir pressure is much larger than the saturation pressure. That is, the fluid is highly undersaturated.
  • Maximum precipitation occurs around the saturation pressure.

Heavier crudes that contain a larger amount of asphaltene have very few asphaltene precipitation problems because they can dissolve more asphaltene. Leontaritis and Mansoori[2] and Kokal and Sayegh[3] compiled field cases with asphaltene precipitation problems during primary depletion. Extreme cases include the Venezuelan Boscan crude with 17 wt% asphaltene produced nearly without precipitation, whereas the Venezuelan Mata-Acema crude with 0.4 to 9.8 wt% asphaltene and the Algerian Hassi Messaoud crude with 0.062 wt% encountered serious precipitation problems during production.

Asphaltene precipitation during IOR gas injection

The injection of hydrocarbon gases or carbon dioxide (CO2) for IOR promotes asphaltene precipitation. Numerous field reports and laboratory studies on this phenomenon have been published.[3][4][5][6][7][8][9][10][11] Although it frequently manifests itself at the production wellbore at solvent breakthrough, precipitation can occur anywhere in the reservoir.

Asphaltene precipitation also may occur during solvent injection into heavy oil reservoirs.[12] Butler and Mokrys[13] proposed an in-situ solvent-extraction process for heavy oils and tar sands called VAPEX. This process uses two horizontal wells (one injector and one producer). The injection of solvent (e.g., propane) creates a solvent chamber in which oil is mobilized and drained toward the producer. In addition to the mobilization process, the solvent may induce asphaltene precipitation, which provides an in-situ upgrading of the oil.

Asphaltene precipitation and deposition

Asphaltene characteristics discusses the chemistry of asphaltenes and Thermodynamic models for asphaltene precipitation discusses the thermodynamic equilibrium of asphaltenes in petroleum fluids. Changes in pressure, temperature, and composition may alter the initial equilibrium state and cause asphaltene precipitation.

The region in which precipitation occurs is bounded by the asphaltene precipitation envelope (APE). [Also sometimes called the asphaltene deposition envelope (ADE).] Fig. 1 shows a typical pressure composition APE and a pressure temperature APE.[14][15] For purposes of this page, precipitation refers to the formation of the asphaltene precipitate as a result of thermodynamic equilibrium and deposition refers to the settling of the precipitated asphaltene onto the rock surface in a porous medium. The onset conditions correspond to points on the APE. Within the APE, the amount of precipitated asphaltene increases as pressure decreases from the upper onset pressure to the saturation pressure of the oil. The precipitation reaches a maximum value at the saturation pressure and decreases as pressure decreases below the saturation pressure.

Inside the reservoir, after precipitation has occurred, the asphaltene precipitate can remain in suspension and flow within the oil phase or can deposit onto the rock surface. The main deposition mechanisms are adsorption and mechanical entrapment. The deposited asphaltene may plug the formation and alter rock wettability from water-wet to oil-wet.

Experimental measurements of asphaltene precipitation

Proper planning procedures dealing with the onset of asphaltene precipitation requires knowing the precise conditions under which such precipitation will occur. There are several methods available that allow for such calculations and the ability to estimate when asphaltene precipitation will occur in order and thus how best to prevent and/or deal with it.

Measurements of asphaltene precipitation envelope (APE)

The APE defines the region in which asphaltene precipitation occurs. Accurate measurements of the APE and the amounts of precipitate within the APE are required for design purposes and for tuning existing models. The upper pressure on the APE is denoted by pAu and the lower pressure on the APE is denoted by pAℓ. Several techniques are available for determining the onset of precipitation with various degrees of accuracy.

Gravimetric technique

This technique[4][16] is conducted in a conventional pressure/volume/temperature (PVT) cell. For a pressure below the pAu, precipitation occurs and larger particles segregate and settle at the bottom of the cell because of gravity. Asphaltene analysis (titration with n-pentane or n-heptane) of the oil shows a decrease in asphaltene content compared with the original oil. Pressure steps must be chosen carefully to capture the inflection point at pAu and pAℓ.

Acoustic-resonance technique

The acoustic-resonance technique has been used effectively to define pAu.[3][17] The live oil is charged at a high pressure (e.g., 8,500 psia) into a resonator cell maintained at the reservoir temperature. The resonator pressure then is decreased at a very low rate (e.g., 50 psia/min) by changing the volume. The depressurization rate decreases with time to a typical rate of 5 psia/min toward the end of the experiment. Acoustic data exhibit sharp changes at pAu and at the oil saturation pressure, ps.

Light-scattering technique

Light-scattering techniques also have been successfully used to measure the APE.[17][18][19][20][21] For dark-colored oil, a near-infrared laser light system (800×10-9 m to 2200×10-9 m wavelength) is required to detect asphaltene-precipitation conditions. The principle behind the measurements is based on the transmittance of a laser light through the test fluid in a high-pressure, high-temperature visual PVT cell undergoing pressure, temperature, and composition changes. A receiver captures the amount of light that passes through the oil sample. The power of transmitted light (PTL) is inversely proportional to the oil mass density, to the particle size of the precipitate, and to the number of particles per unit volume of fluid.[21] The PTL curve exhibits sharp jumps at pAu, ps, and pAℓ.

Flirtation technique

In this method, the cell contents during a depressurization test are mixed in a magnetic mixer, and small amounts of the well-mixed reservoir fluid are removed through a hydrophobic filter at various pressures.[16] The material retained on the filter is analyzed for SARA contents.

Electrical-conductance technique

This technique measures the change in the fluid conductivity with changes in concentration and mobility of charged components.[19][22] Asphaltenes have large dipole moments, and, therefore, the conductivity curve exhibits a change in the slope when precipitation occurs.

Viscometric technique

The key point of this method is the detection of a marked change in the viscosity curve at the onset of precipitation[11][23] because the viscosity of oil with suspended solids is higher than that of the oil itself.

Other techniques

Asphaltene precipitation has been detected through visual observations with a microscope.[5] Measurements of interfacial tension between oil and water[24][25] also can be used to detect the onset. A technique based on pressure-drop measurements across a capillary tube was discussed by Broseta et al.[26]

Comparison of different methods

Fig. 2 shows the results of Jamaluddin et al.‘s[16] comprehensive comparison of measurements with the gravimetric, acoustic-resonance, light-scattering, and filtration techniques on the same oil. These methods, except for the acoustic-resonance technique, determine both the upper and lower APE pressure. The acoustic-resonance technique normally provides only the upper onset pressure. In addition to APE pressures, the gravimetric and filtration techniques also give the amount of precipitated asphaltene within the precipitation region. The gravimetric and filtration techniques are more time consuming than the acoustic-resonance and light-scattering techniques. Fotland et al.[22] showed that the electrical-conductance technique can determine both precipitation onset and amounts of precipitate that are consistent with the gravimetric technique. The advantage of the viscometric technique is in its applicability to heavy crude oil, which may give some difficulties to light-scattering techniques, and in the low-cost equipment. In many cases, two measurement techniques are applied to the same oil to enhance data interpretation. MacMillan et al.[19] recommended the combination of light-scattering and electrical-conductance techniques, while Jamaluddin et al.[16] suggested the simultaneous application of light-scattering and filtration techniques.


The reversibility of asphaltene precipitation is a subject of some controversy.

  • Fotland[27] and Wang et al.[28] suggested that asphaltene precipitation is less likely to be reversible for crude oils subjected to conditions beyond those of the precipitation onset.
  • Hirschberg et al.[5] speculated that asphaltene precipitation is reversible but that the dissolution process is very slow.
  • Hammami et al.[21] reported experimental measurements that seem to support this conjecture. They observed that asphaltene is generally reversible but that the kinetics of the redissolution vary significantly depending on the physical state of the system.

Hammami et al.[21] illustrates the laser-power signal (light-scattering technique) from a depressurizing and repressurizing experiment on a light oil that exhibits strong precipitation behavior. The laser-power signal increased linearly as the pressure decreased from 76 to 56 MPa. This increase results from the continuous decrease of oil density above the bubblepoint as the pressure is reduced. With further depletion between 56 and 52 MPa, a large drop (one order of magnitude) in the laser-power signal occurred. The onset of asphaltene precipitation was estimated to be 55.7 MPa and the laser-power signal dropped to a very low level at 45 MPa. The bubblepoint pressure for this oil is 33.5 MPa. On repressurization of this oil from 27 MPa (7 MPa below the bubblepoint), almost the entire laser-power signal was recovered, but the signal followed a slightly different curve. They further show that the repressurization laser-power curve lags the depressurization curve, which is an indication that the kinetics of redissolution is slower than the kinetics of precipitation. Their analysis also shows that the ultimate laser-power value reached from repressurization is higher than the predepletion value. Hammami et al.[21] suggested that a large fraction of the precipitated asphaltene (the suspended solid) could easily go back into solution while a smaller fraction exhibits partial irreversibility or slow dissolution rate. The oil at the end of the repressurization process is partially deasphalted and is slightly lighter that the original oil.

Joshi et al.[29] performed further experiments to study the reversibility process. Their results corroborate the observations of Hammami et al.[21] for depressurization and repressurization experiments at field conditions; however, they observed that the precipitation caused by the addition of alkane at atmospheric conditions is partially irreversible. They explained that asphaltene precipitation with pressure depletion at field conditions (field asphaltenes) results from the destabilization but not the destruction of asphaltene micelles. On the other hand, asphaltene precipitation caused by the addition of an alkane solvent in the laboratory under atmospheric conditions (laboratory asphaltenes) strips the asphaltene micelles of their resin components, and the restoration of reformed micelles is a very difficult process.

Similar experimental results on partial irreversibility were obtained by Rassamdana et al.[30] with an Iranian oil and different alkane solvents at atmospheric conditions. The laboratory asphaltenes from Joshi et al.[29] and Rassamdana et al.[30] were precipitated from light oils. Peramanu et al.[31] performed precipitation experiments with Athabasca and Cold Lake bitumens and n-heptane solvent and found the process completely reversible. It could be argued that in heavy oils and bitumens, larger amounts of resins and asphaltenes facilitate the reversibility of asphaltene precipitation with alkane solvents; thus, precipitation behaviors for light oils and heavy oils/bitumens are quite different and need to be examined separately.

Many of the references in the sections above contain data on precipitation caused by pressure depletion. Additional data can be found in Hirschberg et al.[5] and Burke et al.[4]

Asphaltene precipitation during rich-gas and CO2 flooding

Hirschberg et al.[5] presented static precipitation data of a recombined crude oil with the separator gas, a lean gas, and a rich gas. The results show that precipitation is more pronounced with rich gas and that the injection of separator gas could induce asphaltene precipitation at reservoir conditions. Burke et al.[4] reported comprehensive static precipitation data for six recombined reservoir oils and different hydrocarbon gases. Their results indicate that precipitation depends on the composition of the crude oil, the added solvent, and the concentration of asphaltene in the crude. They also observed that for oil/solvent mixtures that exhibit a critical point on the p-x diagram, maximum precipitation occurred at the critical point.

Monger and Fu[32] and Monger and Trujillo[6] provided extensive data on asphaltene precipitation in CO2 flooding. In Monger and Trujillo,[6] 17 stock-tank oils with gravity ranging from 19.5 to 46.5°API were used in a variable-volume circulating cell that could reproduce multiple-contact experiments. The temperature was set to 114°F (319 K) and run pressures were set above the minimum miscibility pressures. Fig. 3 shows the amounts of precipitation induced by CO2 in the variable-volume circulating cell vs. the n-C5 asphaltene content of the stock-tank oil. This figure shows that the CO2-induced precipitate is not the same as the n-pentane precipitate from the stock-tank oil.

  • For Samples 1, 2, and 8, the extent of precipitation is substantially less than the asphaltene content.
  • For Samples 3 and 9, the extent of precipitation exceeds the asphaltene content.

They concluded that the precipitation of asphaltene by CO2 was neither complete nor exclusive. Some asphaltenes can remain suspended, and other heavy organic compounds can precipitate. It also was observed that precipitation usually occurs in the development of miscibility. Srivastava et al.[9][10] studied asphaltene precipitation for Saskatchewan Weyburn’s oil with CO2 and found that precipitation started to occur at 42 mol% CO2 concentration in a static test. After that, there was a linear increase in asphaltene precipitate with CO2.

It has been reported that asphaltene precipitation from static tests may be quite different from dynamic tests. Parra-Ramirez et al.[33] performed static and multiple-contact precipitation experiments with a crude oil from the Rangely field and CO2. They observed that live oils yielded significantly higher amounts of precipitates than the corresponding dead oil and that multiple-contact experiments gave rise to more precipitation than single-contact experiments.

Field asphaltene precipitates resulting from a rich-gas or CO2-injection process are different from laboratory asphaltenes induced by the addition of alkane. This field asphaltene is also different from the field asphaltene resulting from pressure depletion, and its nature also varies with the composition of the injection fluid.


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  2. Leontaritis, K.J. and Mansoori, G.A. 1988. Asphaltene deposition: a survey of field experiences and research approaches. J. Pet. Sci. Eng. 1 (3): 229–239.
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  7. Novosad, Z. and Costain, T.G. 1990. Experimental and Modeling Studies of Asphaltene Equilibria for a Reservoir Under CO2 Injection. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 23-26 September. SPE-20530-MS.
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  17. 17.0 17.1 _ Cite error: Invalid <ref> tag; name "r17" defined multiple times with different content
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  33. Parra-Ramirez, M., Peterson, B., and Deo, M.D. 2001. Comparison of First and Multiple Contact Carbon Dioxide Induced Asphaltene Precipitation. Presented at the SPE International Symposium on Oilfield Chemistry, Houston, 13-16 February. SPE-65019-MS.

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See also

Thermodynamic models for asphaltene precipitation

Wax precipitation

Asphaltene deposition and plugging

Asphaltene problems in production

Asphaltenes and waxes