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Fluid pressure detection and porosity evaluation from well logs are largely based on an assumed relationship between high fluid pressures and high porosities due to undercompaction. However, few data have been presented which demonstrate to what extent porosities are higher in overpressured than in normally pressured shales of similar type, and how this porosity difference is detected by the responses from standard logs. Jurassic intra-reservoir shales on Haltenbanken (offshore mid-Norway) are particularly well-suited for such an investigation because (a) the area is subdivided into two, major, distinctive pressure regimes (one normally pressured, the other highly overpressured) and (b) the lithology, depositional environment and present burial depth do not vary significantly across the area.

Log comparisons reveal that neutron and density responses show no significant porosity difference between the two regimes, whereas sonic and resistivity responses show higher (apparent) porosities in the overpressured area. It is thus suggested that porosity is unaffected by differences in fluid pressures, but that the sonic and resistivity logs are reacting to textural changes induced in the rocks by overpressuring rather than high porosities due to undercompaction.

High fluid pressures in combination with low shale porosities could be explained by pressure unloading (i.e., fluid overpressuring post-dating shale compaction), and this cannot be ruled out from the Haltenbanken data. However, log data from North Sea shales also show that formation density does not significantly vary with fluid overpressuring, whereas sonic log data decreases with depth irrespective of overpressuring. As it is unlikely that fluid overpressuring in all of these formations postdated compaction, it appears that shale porosity reduction may proceed without significant hindrance by fluid overpressuring.

These findings suggest that standard principles applied to pore pressure evaluation from well logs may not always be valid, thus partly explaining the large degree of uncertainty attached to such work. Furthermore, basin modeling of fluid flow, overpressure buildup, hydrofracturing and hydrocarbon migration appears to rely on equations which give improper descriptions of fluid transport in shales.

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