What are asphaltenes?

There are many definitions of asphaltenes. Strictly speaking, asphaltenes are the

crude oil components that meet some procedural definition. A common definition is that

asphaltenes are the material that is (1) insoluble in n-pentane (or n-heptane) at a dilution

ratio of 40 parts alkane to 1 part crude oil and (2) re-dissolves in toluene.

The procedure should also specify the temperature at which the mixing and

separation takes place, the amount of time that must elapse before asphaltenes are

separated from the oil/alkane mixture, and even the method used to accomplish the

separation (filter size, filtration rate), since all of these factors can affect the final result.

There are several standardized procedures (e.g., ASTM D2007-93, IP 143), but in reality

every lab uses its own procedure. These may vary a little or a lot from the standards.

Typical results of such separations are shown in Fig. 1 for asphaltenes from Mars-P crude

oil. Both were formed in mixtures of 40 parts alkane to 1 part oil, separated by filtration,

and allowed to dry. They differ in color and in texture. Material separated with still

lower molecular weight alkanes (e.g., propane) would be sticky and more liquid-like.

One way to think about the material that separates from crude oil or bitumen into

the asphaltene fraction was suggested by Long in 1981. The material in the asphaltene

fraction is high in one or more of the following properties: molecular weight, polarity, or

aromaticity, as illustrated schematically in Fig.2 for n-C5 and n-C7 as the precipitants.

Some would argue that the n-C7 asphaltenes are the “real” asphaltenes, whereas

the n-C5 material is a mixture of asphaltenes and resins. Although these discussions have

consumed enormous amounts of time and energy, they do not help with the task of

understanding and predicting asphaltene phase behavior. It is sufficient to be aware that

there is a continuum of material—generally at the high end in molecular weight, polarity

and aromaticity—some of which may separate into an asphaltene-rich phase in response

to changes in pressure, composition, and/or temperature.

Standardized asphaltene separations provide a useful way to quantify the amount

of material present in a crude oil that is insoluble in an excess of normal alkanes, but it is

not at all clear that this is really what we most need to know about asphaltenes. Oils with

significant amounts of asphaltenes often can be produced without any asphaltene-related

problems, whereas severe asphaltene problems have been reported for some oils with

amounts of asphaltenes that are barely measurable.

When do asphaltenes cause problems?

Asphaltenes can cause problems in oil production, transportation, and processing.

Whether or not asphaltenes cause problems is unrelated to the amount of asphaltene in

the oil. What is important is the stability of those asphaltenes and stability depends not

only on the properties of the asphaltene fraction, but also on how good a solvent the rest

of the oil is for its asphaltenes. As recognized by de Boer et al. (1995), light oils with

small amounts of asphaltenes are more likely to cause problems during production than

heavy oil with larger amounts of material in the asphaltene fraction. The heavier oil also

contains plenty of intermediate components that are good asphaltene solvents whereas the

light oil may consist largely of paraffinic materials in which, by definition, asphaltenes

have very limited solubility. Asphaltenes in heavier oils can also cause problems if they

are destabilized by mixing with another crude oil during transportation or by other steps

in oil processing.

Unstable asphaltenes can form a separate phase that might plug the oil-bearing

rock formation near a well. They can also aggregate at oil/water interfaces where they

stabilize water-in-oil emulsions or at oil/solid interfaces where they can alter surface

wetting properties or accumulate and plug well bores and flow lines. The first step

toward predicting and avoiding any of these problems is knowing how to evaluate

asphaltene stability.

Onset of asphaltene instability.

Although asphaltenes probably exist as aggregates in crude oils at most

conditions, those aggregates can form a separate, visible phase if the solubility condition

in the oil falls below the level required to maintain a stable dispersion. Many different

methods are used to pinpoint the onset of asphaltene instability. The simplest is the spot

test introduced by Oliensis (1933).

Figure 3. Oliensis spot test: the uniform spot on the left represents an oil in which the asphaltenes

are stable whereas the dark-centered spot on the right is diagnostic of unstable asphaltenes.

There are many methods currently in use to detect the onset of asphaltene

instability. These include light scattering, particle size measurements, microscopic

observation, and others. Methods vary in sensitivity. Some are more readily automated

than others. All suffer to some extent from interference due to other suspended particles.

Direct comparisons are often frustrated by differences among samples. On balance,

microscopic observation, either alone or in combination with other techniques, provides

the most direct information about the appearance of suspended particles including

asphaltenes, as described in the following section.

Crude oils under the microscope.

Microscopic observations are commonly used to establish the appearance or

disappearance temperatures of waxes in crude oil, but are less often used as tools to

diagnose other crude oil problems. We have long advocated microscopic observation for

identifying the onset of asphaltene flocculation (Buckley, 1996)

Examples of particles that are obviously asphaltenes are shown in Fig. 4 for two

different crude oils and different instability conditions. In both cases asphaltenes were

precipitated by addition of n-pentadecane. The 50 μm bar in Fig. 4b is roughly valid for

all the oil images in Figs. 4-7.

(a) C-F2-03 crude oil – very unstable (b) Tensleep crude oil – near onset

Figure 4. Examples of the microscopic appearance of asphaltenes precipitated from crude oils with n-C15.

Wax crystals can be visible in a crude oil below its wax appearance temperature.

We use crossed polarizing filters to identify wax crystals, since only crystalline material

that can rotate light shows up at bright spots through the crossed filters. The size of wax

crystals can vary in different crude oils. Figure 5 shows tiny crystals that are not visible

in transmitted light, but are clearly evident when the sample is placed between two

polarizing filters.

Emulsified drops of water are often visible in oil samples. Figure 7a shows an

oily sample from a clean-up site with spherical water droplets. Often the emulsified

water separates when the oil is diluted with n-alkane to produce asphaltenes, but when n-

C15 is added to this sample, some water remains and appears to be associated with

asphaltene aggregates

What are resins?

Just as the asphaltenes have only a procedural definition, resins also are

procedurally defined. There are at least two approaches to defining resins. In one

approach the material that precipitates with addition of propane, but not with n-heptane,

is considered to constitute the resins. There is no universal agreement about the

propane/n-heptane pair, but the general idea is that resins are soluble in higher molecular

weight normal alkanes, but are insoluble in lower molecular weight alkanes.

A standard method exists to quantify resins by a completely different approach. It

involves a time-consuming chromatographic separation of de-asphalted oil into saturates,

aromatics, and resins, the so-called SARA analysis (Fig. 8). Asphaltenes must be

removed before the fluid is introduced onto the chromatographic column because

quantitative removal from the column is impossible. The temptation to develop in-house

shortcuts is unavoidable, making inter-lab comparisons problematic, if not impossible.

The method used in our lab is documented in Fan and Buckley (2002).

Considering the very different methods of preparation, it seems unlikely that the

polar fraction from the chromatographic separation is chemically equivalent to the

propane insolubles, but both are referred to as resins in the literature. The reader should

exercise due caution. Resins, however defined, are likely to include species that

contribute to the overall solvent quality of the oil with respect to its asphaltenes.

What asphaltenes are NOT.

While it is difficult to say with any specificity what asphaltenes are, there are

some things that they probably are not. Asphaltenes are not a specific family of

chemicals with common functionality and varying molecular weight. An example of a

family of chemically related homologs is the fatty acids. Molecules in the asphaltene

fraction can have many different sorts of polar functionality as well as varying molecular

weight. Their only unifying property is insolubility in a specified n-alkane.

Many hypothetical structures can be drawn to match the average amounts of

nitrogen, oxygen, sulfur, and aromatic character measured for asphaltenes. These

average structures generally do not represent the properties of asphaltenes very well.

Asphaltenes probably are not dispersed in resin-coated inverse micelles. The

concept of resins “peptizing” asphaltenes has long been an article of faith in the

asphaltene literature, despite the fact that this widespread picture of asphaltene stability

has never been scientifically validated. Many studies and models of asphaltenes begin

with the assumption that the resin/asphaltene relationship is the key to understanding

asphaltenes. Nevertheless, the scientific method demands that assumptions be verifiable

and that models be predictive. Neither is true of micellar descriptions of asphaltenes.

Material in the asphaltene fraction does form aggregates. That’s why standard

measurements of molecular weight are seldom in agreement and can produce very high

estimates of molecular weight. Asphaltene aggregates may well reach sizes that qualify

them as colloids (one dimension in the range of 1 nm to 1μm). Colloids can behave

differently from true solutions because of the effects of small size and high surface area,

but that’s a subject for another FAQ.

Solid or liquid?

Asphaltenes separated with n-heptane typically are shiny black solids (Fig. 1b).

From this appearance, they are often assumed to be crystalline, but in fact they are

amorphous. Solutions containing visible asphaltene aggregates do not transmit any light

through crossed polarizing filters, unless they also contain wax crystals.

There is much less difference in appearance among asphaltene aggregates in

crude oil before separation and drying. The characteristic appearance shown in Fig. 4 has

recently been explained as evidence that the asphaltenes are separating into a heavy phase

that is below its glass appearance temperature (Sirota, 2005). Describing asphaltene

phase behavior as a liquid-liquid separation, as suggested by Hirschberg et al. (1984), has

led to models that are increasingly successful. The current evidence is consistent with the

view that asphaltenes are liquids that may be in a glassy state, depending upon

temperature.

Do’s (and Don’ts) of asphaltene characterization.

Evaluation of asphaltene stability is not difficult, but there are some common

pitfalls to be avoided. Two types of information are needed:

(1) solubility parameter of the oil, and

(2) solubility conditions at the onset of asphaltene instability (for a given

precipitant).

The information that is usually available is also of two types:

(1) conditions (either volume of added n-heptane and toluene or pressure) at

which asphaltenes are first observed, and

(2) oil gravity or density.

An important question is “How does one get from the information available to

appropriate values of solubility parameters of the oil and at the mixture at onset of

asphaltene instability?”

Some methods of asphaltene detection (especially light scattering) require that the

oil be diluted with an asphaltene solvent, usually toluene, to make a less opaque mixture.

Many different researchers have noticed a simple linear relationship between the amount

of toluene added and the amount of precipitant required to destabilize asphaltenes as

illustrated in Fig 9. This linear relationship persists to very high dilution (c.f., Cimino et

al., 1995). The slopes and intercepts of these straight lines can be used as relative

measures of stability for comparing different oils, precipitants, and solvents.

More recently, however, several groups have used the slopes and intercepts to

deduce solubility parameters of oil and onset conditions. They reason that the linear

relationship implies a constant value of the onset solubility parameter—sometimes

referred to as the critical onset solubility parameter—that does not depend on the extent

of dilution. At high dilution where the oil does not contribute significantly to properties

of the mixture, the solubility parameter at the onset can be evaluated directly from the

known solubility parameters of solvent and precipitant (e.g., toluene and heptane) and

their volume fractions. Reasonable though it may seem, however, the assumption that

this onset solubility parameter represents a critical value that is constant for all

proportions of oil, solvent, and precipitant is NOT correct (Wang and Buckley, 2003).

It leads to estimates of onset conditions that are biased (usually suggesting that the

asphaltenes are more stable than they really are) and estimates of oil solubility parameter

that are not closely related to oil properties, since there is very little oil in the mixtures at

high dilution. For a thorough discussion of the critical solubility parameter fallacy and of

other ways to estimate solubility parameters of oil and onset conditions see Buckley et al.

(2007).

There is more to the story of asphaltene instability, however, than solubility

parameters. Just as the amount of asphaltenes that precipitates varies with the size of the

precipitant (as shown in Fig. 2), so also the onset conditions vary systematically with

precipitant molar volume. The n-heptane onset is one point, but a few more

measurements are needed to establish a trend that we call the ASphaltene InStability

Trend (or ASIST). Alternatively, average trends established for a wide variety can be

used (Wang et al., 2006) with the single n-heptane onset used to shift the line with

average slope to increasing (less stable) or down (more stable) solubility parameters,

depending on the results for the particular oil of interest. With ASIST established for an

oil of interest, instability onsets of n-alkanes intermediate in molar volume between those

measured can be predicted. Onsets in mixtures of n-alkanes can also be calculated. With

additional information including (1) standard PVT test results, (2) compositional

analyses, and (3) temperature effects on ASIST, estimates of the effects of changing

pressure on asphaltene stability can be made by extrapolating ASIST to molar volumes of

mixtures of the light ends (Wang and Buckley, 2001).

Like other colloids, asphaltene aggregation can be very slow near the onset of

instability and much faster as solubility conditions worsen. In continuous or step-wise

processes where precipitant is added or pressure changed, it is easy to overshoot if

equilibration times are not sufficient. Some of the differences reported for different

measurement techniques are caused by discrepancies in equilibration times.