In oil and gas exploration, many questions relating to the petroleum system in a basin are addressed qualitatively and these qualitative models are used to predict how traps might have been charged. However, basin-scale petroleum migration simulators can provide valuable quantitative insights into the reservoir assets, including volumes of in-place petroleum, estimating fill-spill routes, evaluating filling scenarios and assessing connectivity between compartments. Instead of a static mapping of the fluids into a reservoir system, it becomes possible to predict where and how the fluids will flow into the reservoir under different pressure and temperature conditions. Conventional fluid flow modelling approaches based on the the full D'Arcy Law is computationally ineffective for models containing more than a few million cells, i.e. for typical basin scale models. A new computational approach1,3 based on invasion-percolation (IP-based) technique takes advantage of the special flow regime of petroleum migration. It honors a special gravity and capillary dominated flow regime of petroleum migration.

Besides the qualitative appraisal of migration routes and petroleum presence, petroleum accumulations were quantitatively estimated using the model-based approach.

Description of the Studied Area

The studied area is located in the south central West Siberian Basin and covers the area of the Kaymissov arch and the Nyurol depression junction. The known structural traps are gentle anticlines whose flanks seldom dip at more than 2 °. Structural closures vary from several tens of metres up to 150 m. Faults are rare. Most of discoveries have been made over basement uplifts, but it has been found that prospective Upper Jurassic reservoir rocks are absent on their crests. These reservoir rocks onlap the flanks of the uplift and form pinch-out stratigraphic traps. The traps are developed in the transitional zone from Upper Jurassic marine facies in the central part of the West Siberian Basin to continental facies in the SE and SW basin margin. Probable stratigraphic traps are formed by nearshore sand bars and sandstones of tidal channels. Shales of the Bazhenov and Georgiev Formation form the regional seal for these traps.

Numerous oil-source rock correlations proved the shales of the Bazhenov Formation to be the only source rock for oil-pools of the studied area2,4. The organic matter in the Bazhenov Formation is derived from plankton and bacteria. The TOC content ranges from 5 to 24% and generally exceeds 10–12%. In central parts of depressions, TOC is down to 9 percent because of losses due to oil generation. The kerogen is of type II, containing 7–8.5 percent hydrogen and is strongly oil-prone. In the upper part of the oil window, the hydrogen index (HI) is as high as 600–700 mg HC/g TOC. With increasing maturity, HI decreases to 300–450 mg HC/g TOC at the base of the oil window.

Materials and Methods

Thermolytic hydrocarbon analysis ("Rock Eval" technique) was applied to estimate the potential of the source rock and its maturaty. A suit of more than 2000 core samples from Bazhenov formation shales was analyzed.

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