Three-Dimensional Basin and Petroleum System Model of the Cretaceous Burgan Formation, Kuwait: Model-in-Model, High-Resolution Charge Modeling
Jan Frederik Derks, Oliver Swientek, Oliver Swientek, Oliver Thomas Fuchs, Armin Kauerauf, Meshari Al-Quattan, Mariam Al-Saeed, Mubarak Al-Hajeri, 2012. "Three-Dimensional Basin and Petroleum System Model of the Cretaceous Burgan Formation, Kuwait: Model-in-Model, High-Resolution Charge Modeling", Basin Modeling: New Horizons in Research and Applications, Kenneth E. Peters, David J. Curry, Marek Kacewicz
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In basin and petroleum system modeling, the spatial resolution of models is too coarse to cover all of the relevant geologic processes that occur in reservoirs. Reservoir models are built on a static (time invariant) grid and cannot cover the charge history of a field or processes related to changing geologic structures through time. A new method to combine regional-scale petroleum system models and local reservoir- or prospect-scale models was developed and applied to an oil field in Kuwait. In the field, heavy oil zones occur at the original oil-water contact and also in stratigraphic and structural positions above it. Heavy oil occurs in the highly permeable Fourth Sand and Middle Third Sand of the Burgan Formation in the field. This study demonstrates that the heavy oil distribution in those layers can be explained by the petroleum charge history. An early charge from the Cretaceous Makhul Formation was replenished by the Cretaceous Kazhdumi Formation, the stratigraphic equivalent of the Burgan Sands. These sediments were deposited in the area of the Dezful Embayment of the Zargos Fold Belt. No Jurassic charge, breaking through the Gotnia evaporites, is needed to fill the structures of the Cretaceous Burgan reservoirs in the field. Well data and the results of the high-resolution petroleum system model covering the area of the oil field and describing the distribution of charge from the regional model to the field scale lead to the conclusion that the heavy oil zones are mainly the result of gravity segregation, although some influence of water washing cannot be excluded.
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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.