Inversion of seismic data and quantification of reservoir properties, such as porosity, lithology, or fluid saturation, are commonly executed in two consecutive steps: a geophysical inversion to estimate the elastic parameters and a petrophysical inversion to estimate the reservoir properties. We combine within an integrated formulation the geophysical and petrophysical components of the problem to estimate the elastic and reservoir properties jointly. We solve the inverse problem following a Monte Carlo sampling approach, which allows us to quantify the uncertainties of the reservoir estimates accounting for the combination of geophysical data uncertainties, the deviations of the elastic properties from the calibrated petrophysical transform, and the nonlinearity of the geophysical and petrophysical relations. We implement this method for the inference of the total porosity and the acoustic impedance in a reservoir area, combining petrophysical and seismic information. In our formulation, the porosity and impedance are related with a statistical model based on the Wyllie transform calibrated to well-log data. We simulate the seismic data using a convolutional model and evaluate the geophysical likelihood of the joint porosity-impedance models. Applying the Monte Carlo sampling method, we generate a large number of realizations that jointly explain the seismic observations and honor the petrophysical information. This approach allows the calculation of marginal probabilities of the model parameters, including medium porosity, impedance, and seismic source wavelet. We show a synthetic validation of the technique and apply the method to data from an eastern Venezuelan hydrocarbon reservoir, satisfactorily predicting the medium stratification and adequate correlation between the seismic inversion and well-log estimates for total porosity and acoustic impedance.

The Ncogene turbidite systems of Green Canyon and Ewing Bank lease areas in the northern Gulf of Mexico are amajor exploration play. The regional sequence stratigraphy for this area has been interpreted to help define the potential areas for future exploration. Data base consists of 6300 miles of 2-D multifold seismic data well log data for 175, wells, and biostratigraphy from 180 wells. Four main intervals have been identified, which reflect different kinds of turbidite systems based upon lithologies and seismic facies. Exploration concepts must be different in each of the four intervals because of the different nature of the turbidite systems. Paleoecology data indicate that deposition of these turbidite systems occurred in bathyal water depths. Lower Pliocene sediments (5.5 to 3.0 Ma) include the 5.5, 4.2 and 3.8 sequence boundaries. The interval consists of sandrich turbidite systems. The upper Pliocene interval (3.0 to 1.4 Ma) comprises the 3.0, 2.6, 2.4, 1.9 sequence boundaries. The interval is thin in the eastern portion of the area and becomes thicker to the west. Sands develop only in the western portion of the area. The interval corresponds to when the Mississippi River avulsed to farther in the western Gulf of Mexico and sediment supply decreased significantly. The lower Pleistocene interval (1.4 to 0.7 Ma) includes the 1.4, 1.1 and 0.8 Ma sequence boundaries. The interval is predominantly shale-rich with localized sands developing in channel-levee systems and unchannelized sands. The upper Pleistocene interval (0.7 Ma to Present) consists of shale-dominated turbidite systems. Notable submarine canyons develop in this interval to the east.

Seismic profiles, well logs, biostratigraphic data, and cross section restorations were integrated to investigate the relationships between salt tectonics and sedimentation in northern Green Canyon, Ewing Bank, and southwestern Eugene Island. Preliminary results address three aspects of salt-sediment interaction. First, minibasins have characteristic stratigraphic stacking patterns that evolve from ponded to bypass settings. The transition may occur entirely within the slope environment or be associated with shelf progradation through the minibasin. The shift can sometimes be related to salt evacuation, and in other cases to regional variations in the location and volume of clastic input. Second, different types of salt bodies have varying bathymetric expressions that may affect sequence thicknesses and facies development: reactive diapirs are overlain by graben at the sea floor; passive diapirs usually create asymmetric highs, with smooth slopes on some flanks and steep scarps on others; and diapirs modified by contraction are marked by broad topographic highs. Third, models of salt sheet emplacement by extrusion at the sea floor have important implications for the spatial and temporal shifting of sedimentation patterns. Salt bodies originally covered by condensed sections become major minibasins, while bathymetric lows that serve as turbidite conduits and depocenters may be overridden by allochthonous salt sheets. Because complex salt/sediment geometries in any area are genetically linked to surrounding basins and salt bodies, the interactions between deformation and sedimentation can be understood only by reconstructing the regional evolution of both salt and sediments. Although a daunting task, such efforts will aid in the exploration for hydrocarbons, especially in the sub-salt province.

This paper is based on the work performed during the design, implementation and operation of Cascade and Chinook fields and it provides an overview of the Cascade and Chinook fields' reservoirs, part of the emerging Ultra-Deepwater Wilcox Trend in the Gulf of Mexico. A general picture of the structure, stratigraphy, depositional facies, and petrophysics of each field will be given. Reservoir engineering parameters will also be discussed as well as the initial field development. The main result of this work is a consistent integration of all available data, following a recommended workflow process, aiming to build a geologically coherent and realistic reservoir models for these fields. The match of real field production information with the dynamic flow models allows the reduction of uncertainties of the scenarios and better support for the production forecast. From the integration of seismic, logs, fluids, cores and production data has emerged structural models similar for both fields: a faulted salt-cored anticline divided roughly into western upthrown and eastern downthrown blocks, populated with amalgamated-to-stacked turbidite sands. The petrophysical model developed considers the geologic background and supports the dynamic flow model. The main technical contribution of the work presented in this paper is an overview of the reservoirs that have pioneering production from the Lower Tertiary (Wilcox) Ultra-Deepwater trend (Walker Ridge area). These fields are the first analogues for a mostly untested trend which is still projected to have significant production potential. Currently, numerous oil & gas companies have several Wilcox fields, prospects, and plays in varying stages of development in the area. The information provided and the modeling approach used in this paper can be applied as guidelines for similar Lower Tertiary reservoirs developments in the deepwater Gulf of Mexico.