Seismic/Pressure/Gravity Magnetics Revisited
Proper two-dimensional and three-dimensional basin modeling relies on accurate seismic processing and interpretation, correct depth conversion of the identified sedimentary layers, reliable modeling of the thermal history of the basin, and understanding of the regional geodynamic setting. Seismic reprocessing using the common reflection surface (CRS) stack technique allows revised interpretation of the structural setting and the evolution of salt plugs in the area of the Glueckstadt Graben, located near the center of the North German Basin (NGB). Reprocessing of seismic data also provides an alternative view of the geodynamic origin of the basin. Reprocessing of data clearly demonstrates the capabilities of the CRS technique to improve the quality of low-fold data. The images display a considerably improved signal-to-noise ratio and much more detail than the common midpoint processing (CMP) of the 1980s. Moreover, a velocity model consistent with the data was built and used to perform prestack and poststack depth migrations. The image of a Jurassic salt plug indicates tectonics similar to observations in the Allertal region at the northern fringe of the inverted Lower Saxony Basin, where overthrusting plays a major role in the evolution of salt structures. Consequently, shortening of the Mesozoic strata was included in the revised interpretation. The reprocessing also provided new insights into the petroleum systems in this area, indicating possible new exploration targets. The results may lead to a new geologic understanding of the area. Instead of a two-story salt plug, steep reverse faults and associated salt structures similar to the features along the Allertal lineament may best explain the investigated seismic line. Furthermore, CRS processing leads to a new view of the shape of the Moho in the center of the NGB. This view supports the assumption that the origin of the NGB may be more related to metamorphic processes during basin initiation than to crustal stretching.
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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.