Conventional seismic attributes often provide satisfactory results, especially in the characterization of conventional reservoirs such as sandstones. This is not so evident with more compact, low-permeability, and apparently uniform reservoirs, which comprise substantial reserves in amounts unthinkable a few decades ago, and whose development seemed almost impossible until very recently. Unconventional reservoirs considered in this article are located in a predominantly Jurassic-Cretaceous rifted depositional basin. The basin shifted into an early sag phase during the late Jurassic and early Cretaceous, resulting in the accumulation of a thick series of carbonates and shales. Tithonian, Berriasian and Valanginian rocks compose the segment of the geologic column under consideration. The studied sedimentary sequence is a highly prolific oil-prone source rock, with total organic carbon (TOC) up to 8 wt% and amorphous organic matter (type I/II kerogen) deposited in a euxinic paleoenvironment which generated sulfur-rich oils.

The use of interpretation tools to help define a more accurate model of a study requires not only the acquired knowledge of the area and its context but also good criteria to select the attributes and processes to be applied and combined during analysis. The basic amplitude volume technique (AVT) attribute enables a wide range of possibilities of representation, interpretation, and analysis, and it forms the basis of the calculation flow to obtain an attribute variant with higher-frequency content meta-attributes along with a visualization as variants of the AVT.

The Late Jurassic-Early Cretaceous Vaca Muerta (VM) Formation in the Neuquén Basin has served as an important source rock for many of the conventional oil and gas fields in Argentina. With the interest in developing and exploiting shale resources in the country, many companies there have undertaken characterization of the VM Formation in terms of the elements of shale plays. Among other characteristics, shale plays can be identified based on the total-organic-carbon (TOC) content; better TOC leads to better production. However, there is no way of measuring it directly using seismic data, and it can be estimated only indirectly. Considering the influence of TOC on compressional and shear velocities and density, geoscientists have attempted to compute it using the linear or nonlinear relationship it might have with P-impedance. Understanding the uncertainty in using such a relationship for characterizing the VM Formation, a different approach has been followed for characterizing it. Because a linear relationship seems to exist between gamma ray (GR) and TOC, in addition to P-impedance, gamma ray is another parameter of interest for characterizing the VM Formation. Using P-impedance and GR volumes, a Bayesian classification approach has been followed to obtain a reservoir model with different facies based on TOC and the associated uncertainty with it. As the first step, different facies were defined, based on the cutoff values for GR and P-impedance computed from well-log data. Then Gaussian ellipses were used to capture the distribution of data in a crossplot of GR versus P-impedance. Next, 2D probability density functions (PDFs) were created from the ellipses for each of the facies. Combining these PDFs with GR and P-impedance volumes, different facies were identified on the 3D volume. Poststack model-based inversion was used to compute the P-impedance volume, and the probabilistic neural-network (PNN) approach was used to compute GR volume. Derived P-impedance and GR volumes correlated nicely at blind wells on the 3D volume, which gave confidence in the characterization of the VM Formation. An overlay of the discontinuity detail in terms of curvature lineaments on the determined TOC content at the level of interest helps in obtaining a more complete picture, which is useful for the planning of horizontal wells.

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In the Golfo San Jorge Basin, Argentina, the main traditional reservoirs are fluvial sandstones, which are thin and usually fall below seismic tuning frequency. The need for an aggressive development of the reserves and the need to open new areas led to a pilot job in a zone of approximately 100 km2, assuming the possibility to go vertically across structural and stratigraphic traps and their combination, using high technology added to the proved workflow. After the carefully traditional seismic structural interpretation of faults and horizons in the area and using seismic attributes, the seismic reservoir characterization was aimed toward the processing and analysis of a seismic geostatistical inversion. Using this technique improved the knowledge of the emplacement, behavior, and occurrence of the reservoir sand bodies, opening new zones and determining development drilling. The method includes geostatistical inversion and its interpretation, results, and improvement of the sequence. Time thickness of the reservoirs, sand probability, and effective-porosity maps for each separate layer were generated and interpreted at the end of the sequence. The results in proposed wells are based on this technique.