Print this pageABSTRACT: Determining Source Rock Maturity Using Direct Measurement vs. Predictive Modeling--Comparison and Application of Five Methods to Hydrocarbon Generation
Vito F. Nuccio
Five methods of determining thermal maturation, using the same samples of Upper Cretaceous Steele Shale from the Powder River basin, Wyoming, indicate different maturation levels and timing of hydrocarbon generation. Three methods were direct-measurement techniques (vitrinite reflectance and Rock-Eval pyrolysis), and two were predictive modeling techniques (time-temperature index and kinetic modeling).
Mean random vitrinite reflectance (%Rm) measurements indicate that the Steele Shale samples are either immature or marginally mature (0.50-0.70% Rm) with respect to hydrocarbon generation. If vitrinite reflectance records maximum burial and temperature, then hydrocarbon generation began shortly before or at maximum burial, which occurred 10 Ma. Rock-Eval pyrolysis data indicate that the samples are marginally mature to mature (Tmax values of 431-444°C; production indices of 0.10-0.40). Similarly, if the Rock-Eval data record maximum maturity of the kerogen, which occurred at both maximum burial depth and temperature, then timing of petroleum generation is constrained to about 10 Ma.
Both of the modeling techniques predict higher levels of maturity than the measured techniques and thus an earlier timing for petroleum generation. Time-temperature index modeling indicates that petroleum generation from the Steele Shale began at about 47-35 Ma, depending on location (i.e., changes in burial history) in the Powder River basin.
Two kinetic models were run because Rock-Eval pyrolysis analyses indicated that the Steele Shale is a mixture of types II and III kerogen. Type II kerogen kinetic modeling indicates that the Steele Shale began to generate oil as early as 40-25 Ma, whereas type III kerogen kinetic modeling indicates little oil generation but some gas generation at maximum burial and temperature 10 Ma.
All of the techniques have innate problems; hence, the true maturity and timing of petroleum generation is probably somewhere between the results of the measured and predictive techniques. The results of the three direct-measurement techniques are comparable; likewise, the two modeling methods give similar results. The two predictive models are based on the same reconstructed burial history and assumed paleogeothermal gradients; therefore, the results are likely to be similar. These models may also overestimate the effect of time on maturation of the Steele Shale.
AAPG Search and Discovery Article #91003©1990 AAPG Annual Convention, San Francisco, California, June 3-6, 1990