Quantitative Assessment of Hydrocarbon Charge Risk in New Ventures Exploration: Are We Fooling Ourselves?
Noelle B. Schoellkopf, 2012. "Quantitative Assessment of Hydrocarbon Charge Risk in New Ventures Exploration: Are We Fooling Ourselves?", Basin Modeling: New Horizons in Research and Applications, Kenneth E. Peters, David J. Curry, Marek Kacewicz
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Basin modeling software includes tools to statistically vary model input parameters, such as fetch area, depth, source thickness, total organic carbon, hydrogen index, temperature gradient, or heat flow, and consider the impact on fluid phase and volumes. We can rank these parameters, but we should be aware of pitfalls. The underlying geologic assumptions may account for the greatest uncertainty in new basin areas, where data are sparse and models remain poorly calibrated. Modeling tools must be flexible enough to allow multiple working hypotheses within the project time frame.
These multiple hypotheses are best evaluated by an integrated project team that includes the basin modeler. The team members’ shared knowledge of regional basin history, tectonics, stratigraphy, and source rock depositional models can provide an advantage in weighing alternative geologic scenarios and hydrocarbon charge risk.
This chapter provides seven examples of modeling pitfalls based on new ventures exploration studies performed using a combination of flow path and two-dimensional models. Although not representative of all possible pitfalls, these examples illustrate the substantial impact of some pitfalls on model outcome.
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Temperature-time–based first-order kinetic models are currently used to predict hydrocarbon generation and maturation in basin modeling. Physical chemical theory, however, indicates that water pressure should exert significant control on the extent of these hydrocarbon generation and maturation reactions. We previously heated type II Kimmeridge Clay source rock in the range of 310 to 350°C at a water pressure of 500 bar to show that pressure retarded hydrocarbon generation. This study extended a previous study on hydrocarbon generation from the Kimmeridge Clay that investigated the effects of temperature in the range of 350 to 420°C at water pressures as much as 500 bar and for periods of 6, 12, and 24 hr. Although hydrocarbon generation reactions at temperatures of 420°C are controlled mostly by the high temperature, pressure is found to have a significant effect on the phase and the amounts of hydrocarbons generated.
In addition to hydrocarbon yields, this study also includes the effect of temperature, time, and pressure on maturation. Water pressure of 390 bar or higher retards the vitrinite reflectance by an average of ca. 0.3% Ro compared with the values obtained under low pressure hydrous conditions across the temperature range investigated. Temperature, pressure, and time all control the vitrinite reflectance. Therefore, models to predict hydrocarbon generation and maturation in geological basins must include pressure in the kinetic models used to predict the extent of these reactions.