THERMAL STATE IN THE NORTH VIKING GRABEN (NORTH-SEA) DETERMINED FROM OIL-EXPLORATION WELL DATA

We can deduce thermal conductivities and thermal gradients from extensively available oil exploration data: geophysical well logs, cores, cuttings, formation thicknesses and temperatures. Thermal conductivity is predicted at three significant scales. First, it is computed at the scale of well-log electrofacies (thicknesses from 1 to 10 m) using a geometric mean model calibrated on laboratory measurements made on the main sedimentary rocks- the electrofacies conductivity is calculated as a function of the mineralogy, the porosity and the saturating fluids. Second, it is estimated at formation scale at each well site (thicknesses from 100 to a few thousand meters) using a serial model that accounts for the anisotropy due to sediment stacking and for temperature effects. Finally, for each formation (thicknesses on the order of 1 km), the average conductivity field is mapped at basin scale (extent on the order of 100 km) using a geostatistical treatment accounting for lateral facies and/or porosity changes. For thermal gradient field reconstruction, the systematic errors associated with the drilling history are removed from temperatures (bottom-hole temperatures) using various techniques depending on data quality. The formation thermal gradient fields are then estimated using a stochastic inversion for temperatures and thicknesses, considering lateral correlations between thermal gradients at well sites. The technique is applied to the Norwegian Viking Graben, a multistage rift basin in the North Sea, where previous studies indicate large lateral and vertical variations in thermal conductivity and thermal gradient fields.