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Abstract: Basin Modelling of Fluid Flow, Migration, Trap Integrity and Overpressuring: Are We All Very Wrong?

BOLAS, HEGE NORDGARD, EIRIK VIK, BRITTA PAASCH, CHRISTIAN HERMANRUD, Present address: Stanford University, Dept. of Geophysics, Stanford, CA94305-2215m, USA, Statoils Research Centre, Postuttak, 7005 Trondheim, Norway

Two-dimensional basin modelling of fluid flow is being used extensively to aid hydrocarbon exploration. Such modelling predicts the build-up of fluid pressures, fluid transport including hydrocarbon migration, and leakage of reservoirs. The fundamental assumption behind such modelling is that sediment compaction is being controlled by mechanical forces only. Accordingly, the effetctive stress (overburden - pore pressure) is modelled to be driving porosity reduction, with the result that overpressured rocks are modelled to have elevated porosity (undercompaction). The resulting fluid flow and overpressures are fundamental to the main results of the modelling, as these are modelled as the driving forces for hydrocarbon migration.

To test the validity of the concept of undercompaction in North Sea shales, and to quantify the extent of porosity elevation as a function of overpressuring, density and sonic log responses and pore pressures from nine different stratigraphic units in 80 different wells were collected. Each stratigraphic unit was analysed as a separate entity in order to separate the effects of overpressuring from those of changing lithology. Contrary to assumptions, the analysis demonstrated that the overpressured rocks did not have higher porosities than their normally pressured counterparts. This result suggested that porosity reduction in the investigated shales was not resulting from mechanical compaction, and that our present style of fluid flow basin modelling could not give reliable results.

To test this hypothesis further, basin modelling of several overpressured wells in the North Sea was carried out. The parameters in the permeability and porosity equations were adjusted until a satisfactory fit between observed and modelled porosity and fluid pressure was achieved. However, the modelled porosity vs. depth history of the sediments deviated significantly from the porosity vs. depth relationships we observe in shale in the North Sea today, irrespective of our choice of input parameters.

We further observed that the significant increase in pore pressure which some formations experience when they are buried below certain depths could not be accounted for by the modelling.

As the data show no signs of undercompaction, and as the modelling based on mechanical compaction gives unacceptable results, it is inferred that mechnical compaction is not the main driving force for porosity reduction in shales. This further implies that the modelled overpressures and resulting fluid flow, including hydrofracturing and cap rock leakage, should be judged with considerable caution.

AAPG Search and Discovery Article #90937©1998 AAPG Annual Convention and Exhibition, Salt Lake City, Utah