Namorado Sandstone Project, Albacora Field (PRAVAP 2) is providing Petrobras new reservoir characterization techniques and methodologies in a short period of time. The project key points are: integrated teams from operational and research areas, matrix management, multidisciplinary and multi-scale approach, selective technology acquisition, and synchronism between the field development and the project timing. This paper summarizes the developments acquired and how they impact the field development. High-resolution stratigraphy and facies analysis coupled with a very detailed structural description and fault mapping provide a reservoir deterministic framework and the base for the preliminary geological and fluid flow models. This model has been very useful for drilling and reducing investment risks during early to intermediate stages of field development. More robust models are being constructed using the deterministic framework as a constraint for the stochastic modeling. An hierarquical facies model was established on the basis of porous systems, sedimentary (composite) and impedance facies. An upscaling technique, based on geopseudo concepts, integrates the facies model into a fluid flow model. Geostatistical tools have been applied in reservoir mapping, and facies and porosity stochastic modeling. 3-D seismic inversion improves the definition of inter well reservoir properties and allows a better incorporation of seismic data into geological models. Imaging logs, and core minipermeametry (specially in cored horizontal wells) have been used in the description of the reservoir heterogeneities and facies not identified in conventional logs. Introduction Petrobras is exploiting its major offshore oil fields with modern production technology in a scenario of reduced number of wells; more horizontal wells and an intensive use of seismics. Reservoir characterization has to fit this scenario with emphasis on integrated techniques and intensive use of well, seismic and production data. The seismic data for reservoir characterization requires special processing and robust seismic inversion techniques. Reservoir characterization methodology PRAVAF' 2 characterization processes were organized according to a multiscale and multidisciplinary approach. Three main work scales were defined according to the common process and products generated during reservoir characterization. The basic idea is to define a geological framework coupled with an hierarquical facies model, in which the relationship between genetic, spatial, geometric and effective flow properties are fully and operationally defined. Microscopic scale - Microscopic characteristics and rockfluid interaction are defined like composition, diagenesis, wettability, skin susceptibility, resistivity and porous systems, described on the basis of rock and ?, K, PC, Kr parameters. Several techniques are used, such as petrologic and image analysis, EMS, RXD and petrophysical analysis. Well and core scale - Basically the sedimentary facies and arrangements of these facies (composite facies) and their well log responses are defined. The common techniques used are the sedimentological analysis, well log interpretation, petrophysics, including the acoustic behavior determination (Vp, Vs, Poison and Young modules). The integration techniques were pursued and the statistics (including nonparametric methods) geostatistical techniques are very important for identification of facies groups, and for quantification of the mutual relationships among rock, well log and peaophysics. Interwell to field scale - A high-resolution and very detailed stratigraphic and structural framework was defined and used as a

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes the reservoir flow simulation study of the Namorado Sandstone, Albacora Field (offshore Brazil). This study is the end point activity − to which the geological description, geostatistical modeling and upscaling results converge − of the project PRAVAP-2, a main project designed to develop technology on reservoir characterization at Petrobras. This paper details work executed by a multidisciplinary team on a flow simulation study performed in a stochastic modeling scenario. We present aspects related to the model construction and the results obtained from the flow simulation study. The fluid flow model considers a deterministic framework built with high-resolution stratigraphy and detailed structural analysis. Twelve stratigraphic units were grouped in six simulation layers. The heterogeneities inside each layer were modeled using a geostatistical approach: we used the Markov-Bayes simulation method to integrate seismic and well data.A multi-step upscaling technique was used to generate the effective petrophysical properties for the fluid flow simulation model. The idea is based on (1) a hierarchical description of the reservoir heterogeneities and on (2) the computation of the effective properties bottom-up through this hierarchy. Three main work scales were defined: "porous systems" (microscopic scale); "composite facies" (log and core scale); and "seismic facies" (interwell to field scale). Effective permeabilities and two-phase pseudo-functions were numerically computed for each facies at each scale.The simulation grid has a corner point geometry, comprising a total of 46,200 gridblocks with areal dimensions of 100m x 100m. The interconnection of layers was modeled by changing the vertical transmissibility distribution.The history matching was performed by the adjustment of the average pressure for the six layers and of the reservoir production history. The results demonstrated that our sophisticated model allowed a very fast history matching. Extrapolations investigated the adequacy of the development plan, in special the type of the well, horizontal or hydraulic fractured vertical, the number and locations of these development wells to be drilled.

The facies and net-to-gross ratio (NTG) modeling methodology presented in this paper has been successfully applied on geological characterization of a giant field at Campos Basin, offshore Brazil. Such methodology aimed to preserve the seismic attribute original trend for NTG property in the facies model. In this way, more reliable horizontal parameters could be determined. These are usually hard to obtain, due to the scarceness and huge spacing between wells in an oilfield at its initial development stages. The technique may be described as follows:Choice of a seismic attribute that shows good correlation with average NTG at wells using programme Log Property Mapping (SIS-Schlumberger Information Solutions). After that one must elaborate a non-reservoir average distribution map (NR=1-NTG map).Generation of reservoir facies proportion maps (three altogether) obtained by facies proportion interpolation at the wells (collocated co-Kriging) using the NTG distribution map as a secondary variable.Determination of horizontal variogram parameters. These are used in the non-reservoir facies simulation (from NTG distribution map) and correlated with vertical variogram range, obtained from well data.Determination of horizontal variogram parameters for each of the three reservoir facies using ratios between horizontal variograms range (two directions) and the vertical ones.Determination of NTG, naming 1 for reservoir facies and 0 for non-reservoir facies. In the modeling phase, mainly in the upscaling step, a particular interval named inter-stratified has been given special treatment. It shows a NTG value around 50% (against a 85% value for the field as a whole) and has been defined in order to preserve the critical reservoir heterogeneities. Once treated in a different way during the upscaling step, its characteristics can be preserved during the scale transfer, and consequently improving history match. Introduction Facies model building may be constructed by two main methods: pixel based (Kriging, SGS) or object based. The choice for the best one depends upon the available information, the characteristics and the geological knowledge about the field. The input data for both is known as the hard data (e.g. wells and facies proportion), which must be respected during simulations, and the soft data (e.g. seismic attributes, variogram parameters), which are used as trends and have differentiated weights within simulations. As a result, each of these methods come up with distinct architecture and facies distribution. This paper intends to describe the phases in the facies and net-to-gross ratio (NTG) modeling (conditioned by maps obtained from seismic attributes) and its use in the upscaling phase in a giant field at Campos Basin. The methodology aims to embrace and preserve the seismic attribute trend for NTG within the facies model itself taking into account facies proportion maps and variograms used in geostatistical simulation. The reservoir is made up of turbiditic sandstones and conglomerates. The main zone may be divided in two stratigraphic subzones: upper and lower. The lower subzone is composed of sandstones and conglomerates deposited in a turbidite channel system. The upper, deposited in a less confined setting, is composed of finer sandstones and intercalated shales. Previously both subzones were thought to be communicated, but after the pilot production started, a differential depletion has been observed between them, indicating that must indicate that the hydraulic vertical communication shows a certain degree of restriction. It has been attributed to an interval named inter-stratified (Inter) that presents a NTG around 50% (against a 85% value for the field as a whole) and located right on lower subzone. Although it is a meaningful heterogeneity such interval cannot be mapped by seismic and it is essential that its characteristics be preserved when the geological grid is upscaled into the simulation one. In order to keep its characteristics and to come to a better production history match the interval was individualizaed within the geological model and treated differently in the upscaling step.

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