Hybrid Gas Condensates and the Evolution of their Volatile Light Hydrocarbons


    A paper of the above title by Keith F. M. Thompson was published in Organic Geochemistry in early 2016 (v 93, pp 32-50). A PDF copy is available from the author upon request through


    Recent work has centered upon the widespread occurrence in conventional reservoirs of liquid-rich gas condensates resulting from the migration of high maturity, high pressure, gases from active source rock regions into adjacent oil reservoirs at distances as great as 140 miles. Such gas streams, impinging upon oil accumulations, result in their gas enrichment, displacement and potential gasification, the latter leading to “hybrid” gas condensates made up of relatively low maturity residual oil liquids with added high maturity gaseous components. Comparison of type cases with a database shows that Hybrid gas condensates are extremely common. Approximately two thirds of oil accumulations also exhibit gas-enrichment, the evident precursor process. A large proportion of gas-impacted accumulations are abnormally pressured. Evaporative and Thermal gas condensates are also characterized in the study.


    A classification of gas condensates and discriminatory characteristics have been developed through the application Slope Analysis (references 1-6), providing thermal history data on the basis of PVT analyses. Slope Factors based on gaseous components are shown for the first time to accurately reflect maturity. Gas-range, or volatile light hydrocarbon (VLH) Slope Factors in unaltered oils exhibit values between 1.45 and 1.6. In conventional HPHT gas condensate reservoirs values close to 2.0 occur at reservoir temperatures between 300F and 325F. Values from 2.5 to 3.5 occur between 340F and 350F, reaching an average of 6.4 in nearly dry gases at 400F (ref. 7). Elevated gas-range Slope Factors occur in liquid-rich shales, e.g., 2.8 in the Montney-Doig source system (ref. 8). Gas condensates in the Eagle Ford source in south Texas exhibit values of the order of 2.3 (ref. 9). Values of 2.4 occur in the 39 API oil of the giant East Texas field of Eagle Ford origin (Thompson, 1992), 140 miles distant. VLH Slope Factors exhibit a multi-modal frequency distribution in Alberta, suggesting that pulses of high pressure gas at discrete levels of increasing maturity were dispersed over wide areas with distribution paths up to 100 miles in length.


    The evolutionary steps decipherable in an oil or gas fluid are of exploration interest. The history of any petroleum fluid and the stages and processes which have occurred in its evolution should be accommodated in a successful basin model. For example, details present in the VLH composition of the majority of evaluated oils provide distinct evidence of gas loss due to migration depletion, i.e., loss of light ends during migration in in carrier beds at pressures lower than the original bubble point.Such evidence is inherited by, and retained in, daughter gas condensates.


    1. Thompson, K.F.M, 1987 Fractionated aromatic petroleums and the generation of gas-condensates. Organic Geochemistry 11, 573-590.

    2. Thompson, K.F.M. (1988) Gas-condensate migration and petroleum fractionation in deltaic systems. Marine and Petroleum Geology 5, 237-246.

    3. Thompson, K.F.M (2002) Compositional regularities common to petroleum reservoir fluids and pyrolysates of asphaltenes and kerogens. Organic Geochemistry, 33, 829-841.

    4. Thompson, Keith F.M. (2004) Interpretation of charging phenomena based on reservoir fluid (PVT) analysis. In “Understanding Petroleum Reservoirs: Towards an Integrated Reservoir Engineering and Geochemical Approach”. Geological Society, London, Special Publications, 237, 7-26.

    5. Thompson, Keith F.M. (2006) Mechanisms controlling gas and light end compositions in pyrolysates and petroleum: applications in the interpretation of reservoir fluid analyses. Organic Geochemistry, 37, 798-817.

    6. Thompson, Keith F.M. (2010) Aspects of petroleum basin evolution due to gas advection and evaporative fractionation. Organic Geochemistry. 41, 370 – 385.

    7. Mankiewicz P.J. et al., 2009. Gas Geochemistry of the Mobile Bay Norphlet Formation. AAPG Bull. 95 1319-1346.

    8. Kuppe, F. et al., 2012, SPE 162824, Liquids Rich Unconventional Montney.

    9. Whitson, C.J. and Sunjerga, S., 2012. SPE 155499, PVT in Liquid-Rich Shale Reservoirs.