The main steps of the sedimentary evolution of the west Lombardian South Alpine foredeep between the Eocene and the Early Miocene are described. The oldest is a Bartonian carbonate decrease in hemipelagic sediments linked with an increase in terrigenous input, possibly related to a rainfall increase in the Alps. Between the Middle Eocene and the early Chattian, a volcanoclastic input is associated with an extensional tectonic regime, coeval with magma emplacement in the southern±cen-tral Alps, and with volcanogenic deposits of the European foredeep and Apennines, suggesting a regional extensional tectonic phase leading to the ascent of magma. During Late Eocene to Early Oligocene, two periods of coarse clastic sedimentation occurred, probably controlled by eustasy. The first, during Late Eocene, fed by a local South Alpine source, the second, earliest Oligocene in age, supplied by the Central Alps. In the Chattian, a strong increase in coarse supply records the massive erosion of Central Alps, coupled with a structures growth phase in the subsurface; it was followed by an Aquitanian rearrangement of the Alpine drainage systems suggested by both petrography of clastic sediments and retreat of depositional systems, while subsurface sheet-like geometry of Aquitanian turbidites marks a strong decrease in tectonic activity.

This paper presents the results of using a new workflow to correct and validate logging-while-drilling measurements (LWD) from horizontal wells, and the impact of the results in the petrophysical answers derived from the measurements. The workflow involves building a layered geological model and modeling the log responses in a model-compare-update loop to obtain the log properties of each layer. While similar methodology has been available in the past, the process was laborious and time consuming, and therefore it was not well applied in the industry. The paper demonstrates how the new process addresses the most common effects in horizontal wells in a timely and efficient manner, allowing it to form a part of petrophysical analysis in high angle and horizontal wells. In high angle and horizontal wells it is often difficult to apply the traditional petrophysical interpretation techniques normally used in vertical wells, due to geometric effects on the data in particular the resistivity logs. These effects include local layering or resistivity anisotropy, and boundary effects such as proximity and polarization horns on the resistivity measurements. Other effects complicating the borehole environment include asymmetric invasion profiles, the presence of cuttings beds and drilling mud segregation. This means that the data is challenging to interpret and the petrophysical answers from horizontal wells are not always fully used in static reservoir models. The inclusion of the corrected petrophysical properties from this processing into the static reservoir model reduces uncertainty and improves model accuracy. The workflow was applied on wells in a development field in North America. The reservoir consists of a few tens of feet thick silty sand and siltstone layers deposited in a shelfal environment. The extended reach wells used in the development of the field have long lateral sections (from 5,000 to 10,000 ft). Due to the geological complexity of the area, the wells often cross multiple layers and faults and are actively steered to optimize reservoir contact. The geological environment from static reservoir model was efficiently confirmed and refined, log responses corrected and verified before being used in the petrophysical analysis. The comparison of log responses between vertical and deviated wells was helpful both for quality control and in the well log modeling phase to assess the correct record of petrophysical properties for the input logs and for the modeling results. The update of the log measurements and resulting improvement in petrophysical answers is presented. The workflow requires strong integration between the Reservoir Geology, Drilling and Petrophysics teams. The paper presents a case study of the application of a new workflow to improve petrophysical answers from logging while drilling measurements in high angle and horizontal wells. The study demonstrates how log modeling in high angle and horizontal wells can be used to improve formation evaluation. The improved formation evaluation and updated...

A workflow applied to achieve a multi-scale characterisation of a carbonate reservoir is presented. Carbonate rocks are strongly heterogeneous due either to complexity of the primary fabric or to diagenetic over-printing. The combination of these features leads to complicated pore systems, thus a proper definition of pore types using either pore size or pore throat size distributions, is important to indirectly capture diagenetic modifications and to get a link to dynamic properties. A new approach was developed in order to define a Rock Type classification (RRT) each time the approaches based on Winland's and Hydraulic Flow Unit methods do not give a reliable core facies characterisation when moving to the log scale. Moreover, the proposed workflow accounts for stratigraphy and seismic since RRT are linked to the elastic properties. In the new MICP-based Rock Typing workflow, RRT are identified by describing dominant pore types using mercury injection (MICP) curves parameterisation and routine core data (RCA). Clustering and subsequent extrapolation of MICP derived RRT to RCA samples, are the first two stages to achieve a predictable classification into the log domain. Log RRT are then defined at the log scale using curves of elastic properties, like Poisson's Ratio (PR), Frame Stiffness (fk) and Flexibility (γk) Factors. These elastic parameters (calculated with the Extended Biot Theory), can capture the effects of pore structure on the petrophysical properties and link RRT prediction at well position to seismic attributes. Since the RRT are characterised in the elastic space, the facies model – properly upscaled – represents the basis to classify elastic attributes from seismic inversion in a Bayesian framework. The seismic classification can then be used as a driver for RRT distribution in the inter-well space into the 3D model. A further benefit is the direct relationship to the original RRT porosity/permeability distributions, when modelling petrophysical properties. This new workflow was a successful solution to define homogeneous reservoir intervals in a carbonate environment characterised by the lack of a significant relationship between depositional facies and petrophysical properties.

Reservoir characterization of laminated turbiditic sequences is often problematic due to the highly anisotropic setting, which affects the formation evaluation from conventional LWD, wireline logs and mudlog data. The reservoir, fluid content and pay petrophysical parameters are usually underestimated. Time and cost constraints can prohibit the utilization of new generation high resolution tools and to perform conventional DSTs. An oil and gas bearing well in deep water Indonesia was accurately evaluated with a relatively low time and cost investment in formation evaluation and data acquisition. Pay, porosity and water saturation were calculated by integrating high resolution image logs with standard wireline logs. An ample dataset of reliable formation pressures and fluid samples were obtained in a thin bed environment from Wireline Formation Testing (WFT) utilizing standard and large size probes. Mini DSTs were carried out to characterize reservoir and fluid properties. Thin beds were recognized using an imaging log in oil base mud and through a Thin Layer Analysis (TLA) approach the net sand calculation was enhanced. The TLA result was cross-checked with an electrofacies profile obtained using standard well logs (density, neutron and gamma ray) and calibrated with the sedimentological core description from other wells. In the final net sand computation beds not corresponding with actual reservoir facies were not considered so that only the effective reservoir was included. The result of this integrated approach resulted in an increase in the net pay evaluation in comparison with the conventional formation evaluation, and confirmed the high potential of nonconventional pay in a deep water environment. An exhaustive reservoir and fluid characterization was also achieved without coring and conventional DSTs.

A mature exploration area has been tested to achieve an integration of various data sources (stratigraphy, sedimentology, well logs, seismic, production, etc.). The studied sequence was subdivided into electrofacies, defined using well-log values, on the basis of core data. Two probabilistic databases were constructed to extend core information on all the wells available through an automatic statistical method:-a "sedimentological" database, in which the electrofacies were defined according to their depositional significance; -a "lithologic" database, in which the electrofacies were defined as lithology and porosity classes.A description of the sequence in terms of depositional systems, environments and lithofacies was obtained by studying the vertical distribution of the electrofacies and their mutual statistical relationships. The results were checked against core data. The integration with porosity and productivity data allowed a depositional model for reservoir and seals. Moreover, some key horizons were defined as sequence boundaries on the basis of significant lithologic and environmental changes. They were tied on seismic lines to define the depositional features and palaeogeographical setting of the area. The stratigraphic succession was split into three depositional sequences representing a three-step coastal progradational phase. The achieved results led us to consider this approach in facies recognition as a helpful support in discriminating between various working hypotheses where core data are not available.