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During a regional seismic interpretation study of leakage anomalies in the northern North Sea, mounds and zones with a highly chaotic seismic reflection pattern in the Tertiary Hordaland Group were repeatedly observed located above gas chimneys in the Cretaceous succession. The chaotic seismic reflection pattern was interpreted as mobilized sediments. These mud diapirs are large and massive, the largest being 100 km long and 40 km wide. Vertical injections of gas, oil and formation water are interpreted to have triggered the diapirs.On the eastern side of the Viking Graben, another much smaller type of mud diapir was observed. These near-circular mud diapirs are typically 1–3 km in diameter in the horizontal plane. Limited fluid injection from intra-Hordaland Group sands, through sand injection zones, into the upper Hordaland Group is interpreted to have triggered the near-circular diapirs.This observed ‘external’ type of mobilization was generated at shallow burial (<1000 m) and should be discriminated from the more common ‘internal’ type of mud diapirism that is generated in deep basins (>3000 m). The suggested model has implications for the understanding of the palaeofluid system, sand distribution, stratigraphic prediction within the chaotic zone, seismic imaging, and seismic interpretation of the hydrocarbon ‘plumbing’ system.

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Hydrocarbon source rocks contain signifi cant volumes of organic matter, are capable of expelling petroleum when heated, and have produced most of the world's known oil volumes. Recently, source rocks have also become recognized as unconventional economic reservoirs. Here we present a new way of identifying, characterizing, and mapping spatial distributions and variations of thick source rocks (>20 m) that is based on seismic data only. This has a signifi cant impact on the prospect risk assessment of petroleum plays. Rock property studies of organic-rich claystones show that the acoustic impedance (AI), which is the product of compressional velocity and density, decreases nonlinearly with increasing total organic carbon (TOC) percent. Claystones mixed with low-density organic matter (TOC > 3%-4%) have signifi cant lower AI and higher intrinsic anisotropy than otherwise similar nonorganic claystones. This gives the top and base source rock refl ections characteristic negative and positive high amplitudes, respectively, which dim with increasing refl ection angle. In addition, the TOC profi le, which is a smoothed TOC percent curve, infl uences the top and base amplitude responses. An upward-increasing TOC profi le has the highest amplitude at the top, while the opposite asymmetry is observed for downward-increasing TOC profi les. By using seismic data, we therefore can map lateral distribution, thickness, variation in TOC profi les, and, with local well calibration, convert AI data to TOC percent. This approach to mapping source rocks may change the way petroleum systems are evaluated.