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.