Upon equilibration of vapor and liquid phases of a petroleum, LHC ratios in the two phases change in opposite directions in proportion to the fugacities of the compounds ratioed, and the differences between them.

    Petroleum engineering addresses these differences employing equilibrium constants, "k" values, defined as the ratio of moles of vapor to moles of liquid for each component of an equilibrated system, be it binary, or of the complexity of petroleum. Values of k depend upon the nature of a given compound, also upon system pressure, temperature and composition. They are thus infinitely variable.

    In petroleum vapor-liquid systems, that is, in the generation of a gas-condensate vapor phase and a residual liquid oil, there is a consistent order in k values by compound class. At C7 this order is expressed in the following inequalities:

    k(2-methylhexane and 3-methylhexane) > k(n-heptane) > k(methylcyclohexane) >k(toluene).

    Thus, toluene is the least volatile, followed by methylcyclohexane, leading to their increase in residual oils. Converse arguments apply to initially formed gas-condensates, though the situation is more complex in the case of later-formed condensates.


    The following paragraph is from the study "Aspects of petroleum basin evolution due to gas advection and evaporative fractionation", Thompson, 2010.

    "An early postulate of entrainment of condensate stripped by gas from oil, followed by migration, was described in a comprehensive evaluation of the San Juan Basin, New Mexico (Thompson, 1980). Within a single, laterally extensive, stratigraphic unit, the Dakota Formation, methane in dry gases and gas-condensates exhibits a gradient in del13C from -37 per mil in the basin center (1.9% Ro) to -46 on the up-dip margin (0.8% Ro). Up-dip gas-condensates and oils in adjacent fields, both occurring in the Dakota Formation, contain gasoline-range hydrocarbons which are alike in their intermediate maturity signatures. Both gas and condensate characteristics are compatible with center-to-margin gas migration."

    Between 1980 and 1987 observational evidence and experimental data accumulated confirming the validity of the basic hypothesis. Today, it is widely recognized and described. For a considerable period, evidence of the advection of highly mature methane from basin center to margins was sparse. A recent publication (Zhang et al., 2011, Organic Geochemistry 42, 1394-1410) concerning the Lungu gas-condensate field in the Tarim Basin reports methanes which are heavier in carbon-13 than numerous accompanying ethanes, clear evidence of the highly mature, allochthonous, nature of the methane. The field is attributed to evaporative fractionation.


    Several of the LHC ratios detailed above (Thompson, 1983) lend themselves to the recognition of evaporative fractionation.

    Table 8 presents LHC ratios developed in three oil vaporization experiments or series, carried out in high pressure cells, employing excess methane. Details are given in Thompson, 1987. Two types of ratio pairs have proven useful, firstly, plotting an aromaticity ratio, either benzene/n-hexane (A), toluene/n-heptane (B) or m+p-xylene/ n-octane (X), versus paraffinicity, employing n-heptane/methylcyclohexane (F), secondly, plotting Heptane value (H) versus Isoheptane Value (I).


    Aromaticity-paraffinicity diagrams, particularly B vs F, have become standard tests for the occurrence of evaporative fractionation. As shown later, the same variables are sensitive to, and may reflect, increasing maturity, biodegradation and the extraction of aromatics by water. Figure 47 plots values of toluene/n-heptane (B) versus n-heptane/methylcyclohexane (F) developed in the 1987 experiments. In the vaporization of both Type II and IIS oils, the initial gas-condensates are depleted in toluene and methylcyclohexane, decreasing B and increasing F. In Type II residual oil there is a marked increase in aromaticity, B, and decrease in paraffinicity (F), changes which are initially much smaller in Type IIS oils, possibly due to complexation. In the Series 3 experiments an oil sample was vaporized with excess methane in eleven progressive steps. Only limited data was recorded, providing values of B, F, H and I in the condensates. Progressive increases in B and decreases in F in the gas-condensates reflect changes of the same nature in the evolving oil residua. The experimental results mirror those seen in nature, as shown for petroleum systems in subsequent illustrations.

    Figure 48 illustrates analogous changes, observed in numerous oils, drawing on the author's data in Table 7, selecting Type IIS oils (Phosphoria Formation and Williston basin carbonates) and Type II oils (Cook Inlet and Dakota Formation, Wyoming and Colorado). The former reflect the trends seen in the above experiments, evidencing original or residual oils after evaporative fractionation. The Type II oils are largely unaltered.

    Figure 49 represents Type IIS Jurassic Smackover Formation oils from Alabama, where various facies of the formation serve as source and reservoir. A trend towards increasing aromaticity is illustrated, noting scale variations between figures. Evaporative fractionation is evidenced in its early stages. Several gas-condensates illustrate the effects of extremely high levels of maturation. These are thermal, not evaporative, gas-condensates. Other gas-condensates, plotting with the oils, are evaporative.

    Figure 50 (Thompson, 1987, p. 589) summarizes the types of alteration reflected in B versus F diagrams from numerous basins and the data value regions characteristic of each, representing both oils and gas-condensates.


    Figures 51 and 52 illustrate the evolution of values of H (Heptane Value) and I (Isoheptane Value) upon experimental evaporative fractionation. These examples and others which will be illustrated show that in initially formed gas-condensates values of both H and I increase above those of the original oil undergoing alteration, frequently rising to values plotting above the Generation Curve. This is regarded as significant in the generation of oils which possess elevated values of H and I, lying above the Generation Curve. Such are postulated to represent the addition of evaporative gas-condensate, a process documented in 52% of the oil fields in western Canada.

    Figures 53 and 54 illustrate H versus I data for petroleum systems in two regions, the Smackover Formation in the US Gulf Coast basin, and the Rocky Mountain San Juan basin of New Mexico. In the former, early stage gas-condensates plot above the generation curve, as do oils to which the addition of gas-condensate is postulated. Residual oils plot below, as illustrated by the trend of the residual oil vector in the experiments of Figure 52. In the San Juan basin, the oils represented are basin-margin occurrences, essentially unaltered, while the gas-condensates are late-stage, representing unseen late-stage residual oils.

    Figure 55 illustrates a Java Sea oil and the condensate generated from its gas cap which plots above the generation curve. The occurrence of a gas cap reflects migration depletion, a special case of evporative fractionation.