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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.

Can hydrocarbon source rocks be identified on seismic data?