Integrating Geochemistry, Charge Rate and Timing, Trap Timing, and Reservoir Temperature History to Model Fluid Properties in the Frade and Roncador Fields, Campos Basin, Offshore Brazil
Published:January 01, 2012
John Guthrie, Christian Nino, Hassan Hassan, 2012. "Integrating Geochemistry, Charge Rate and Timing, Trap Timing, and Reservoir Temperature History to Model Fluid Properties in the Frade and Roncador Fields, Campos Basin, Offshore Brazil", Basin Modeling: New Horizons in Research and Applications, Kenneth E. Peters, David J. Curry, Marek Kacewicz
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Understanding the distribution of oil quality and its impact on the development of deep-water reservoirs is a major challenge in many offshore basins of Brazil. Traditional geochemical approaches have used bulk properties (API gravity, viscosity, and sulfur content) and the biomarker compositions of oils to resolve the effects of source rock facies, thermal maturity, and biodegradation on oil quality in the present-day reservoir. These techniques, however, cannot fully resolve the effects of hydrocarbon charge timing, charge rate, timing of trap formation, and reservoir temperature history on the quality of the oil. In the Roncador and Frade fields, offshore Brazil, lacustrine-derived oils from Upper Cretaceous (Maastrichtian) and lower Tertiary (Oligocene–Miocene) reservoirs have gravities ranging from 14 to 33° API. In Upper Cretaceous (Maastrichtian) reservoirs of the Roncador field, better quality light oil (average, 28° API) occurs in the northeastern part, and mostly heavy oil (average, 17° API) is encountered in the southwestern part. The Frade field to the west of Roncador also contains heavy oil (16–19° API) but in shallower lower Tertiary (Oligocene–Miocene) reservoirs.
Geochemical analyses have identified the depletion of n-alkanes and the presence of 25-norhopanes (demethylated hopanes) in varying proportions in oils from the Frade and Roncador fields of the Campos Basin, offshore Brazil, indicating a complex history of biodegradation and mixing from at least two hydrocarbon charges in the reservoir. This study uses both one-dimensional and multisurface thermal models in the area to help determine charge histories for the source rocks and reservoir temperature histories for the reservoirs. These results are used to evaluate the effects of charge and reservoir temperature histories and biodegradation on the ultimate composition and quality of reservoired oils. An interactive biodegradation tool in Trinity software is used to predict the API gravity, and the results are constrained by the geology and the geochemical composition of the present-day fluids in the reservoir. Several examples of charge rate and timing, trap timing, and temperature history are presented for parts of the Roncador and Frade fields to illustrate the importance of these factors on controlling the quality of oil in the present-day reservoir.
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Basin Modeling: New Horizons in Research and Applications
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.