Since the discovery of the Garoupa Field in the Campos Basin, Rio de Janeiro, Brazil, in 1973, Petrobras has been moving to deeper waters. Subsea engineering and well technologies have been developed and applied to overcome the environmental restrictions. Today more than 50% of Brazil's oil production comes from fields located offshore in water depths over 1,000 m. In this scenario, the Marlim Complex - which comprises the Marlim, Marlim Sul and Marlim Leste fields - plays an important role. Discovered in 1985, the Marlim Field started production in 1991, with a pilot system comprising 7 wells connected to a semi-submersible unit moored in a water depth of 600 m. Currently, the field production is about 85,000 m3/d (535,000 bpd), with 60 producers and 32 water injectors connected to 7 floating production units. As with other Campos Basin turbidites, the Oligocene/Miocene reservoir of Marlim Field presents 3 outstanding characteristics: predictability, from seismic data and geological modeling, excellent petrophysical properties and good hydraulic connectivity. The extensive use of 3D seismics as a reservoir characterization tool allows the reduction of risks and the optimization of well locations. Additionally, 3D visualization techniques provide a new environment for teamwork, where seismic data is interpreted and input into detailed reservoir simulation models. Among the deep water well technologies employed to develop the Marlim Complex it is worth mention: slender wells, high rate well design, horizontal and high angle wells in unconsolidated sands, efficient low cost sand control mechanisms, selective frac-pack with isolation between zones, pressure downhole gauges (PDG's), new techniques for the connection of flowlines and X-mas trees, subsea multiphase pumping and special techniques to remove paraffin in the flowlines. However, new developments are required, such as extended reach wells, selective completion in gravel-packed wells, isolation inside horizontal gravel-packed wells with External Casing Packers (ECP's), smart completion and improved recovery techniques for viscous oil. Much has been learned during the planning and development of the Marlim Field and this knowledge is currently being applied in the development of Marlim Sul and Marlim Leste fields. Some important points must always be observed:the development plans must be defined by using optimization techniques considering the geological risks;the number of wells of the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks;the wells must be designed to allow high production rates, with "rest of life" completions, as simple as possible;the sand control mechanisms must be simple, efficient and low cost,the seismic resolution or the production data analysis must be of sufficient quality to guarantee that there will be good hydraulic connectivity between the producers and the corresponding injectors;the pipelines and risers must be designed to avoid bottle-necks or conditions for deposition of wax or hydrates andthe reservoir management and particularly the water injection system management must be made with an integrated teamwork approach. In this paper we present some aspects of the reservoir engineering and of the development plan of the Marlim Field and briefly discuss how this experience is being used in the development of the neighboring Marlim Sul and Marlim Leste fields. Introduction The Marlim Complex comprises 3 giant deepwater oil fields - Marlim, Marlim Sul and Marlim Leste - located in the Campos Basin, 110 km offshore Rio de Janeiro, Brazil (Fig. 1). Besides the geographic location, these fields have other similarities: the main reservoirs are turbidites of Oligocene/Miocene age; 3D seismic data allows accurate prediction of the reservoir occurrence; rock characteristics are excellent; relative permeabilities are favorable to water injection and well productivities are very high.

This paper was prepared for presentation at the 1999 SPE Reservoir Simulation Symposium held in Houston, Texas, 14-17 February 1999.

Summary This paper presents a multiscale computational model for multiphase flow that implicitly treats upscaling without using pseudofunctions. The model overcomes some practical difficulties related to use of traditional pseudocurves by executing the upscaling and solution processes in one step and taking into account changes in the numerical model in an adaptive manner. Introduction Numerical simulation of petroleum reservoirs is associated with intensive use of computational resources. Advances in petroleum reservoir descriptions have provided an amount of data that cannot be used directly in flow simulations. Geostatistical techniques are able to generate descriptions of heterogeneous reservoirs with great detail in a very fine scale. This detailed geological information must be incorporated into a coarser model during multiphase-fluid-flow simulation by use of some upscaling technique. In numerical simulation processes, equations are discretized and the flow domain is divided into blocks with associated rock properties. This step requires that the geological description be transferred from the flow-properties model to the reservoir simulation. Because of computational limitations, it is not possible to run multiphase-flow simulations at such a scale; therefore, properties must be scaled up and the problem must be solved on a coarser grid. In single-phase flow, the most important parameter to scale up is absolute permeability, and methods for this are well established. When multiphase flow occurs, however, it is also necessary to adjust the phase flow through the connections of the coarse grid. In such cases, the most widely used upscaling technique uses pseudorelative permeabilities. The Kyte and Berry1 method is the most common approach applied to calculate pseudocurves. Their procedure requires two steps:generation of pseudocurves for each block of the coarser grid andsimulation of the model considering such functions. In addition to these generation steps, limitations associated to these pseudocurves restrict their use in a more general way. The procedure we propose uses parameters generated from numerical flow simulation in some regions of the domain to create an equivalence between the description and the simulation scales. By solving a sequence of local problems on the more refined scale, it is possible to achieve good agreement between a coarse and a fine grid without expensive computations on a fine-grid model of the whole reservoir. This procedure does not use multiphase pseudofunction concepts and avoids the computational cost of solving the fine grid. The examples presented here consider 2D, two-phase flow (oil and water) and a black-oil formulation. Results of flow simulation considering homogeneous and heterogeneous porous media are presented. These results are also used to compare this approach with commercial upscaling software. Upscaling Techniques With Pseudofunctions Use of pseudofunctions is the traditional way to perform upscaling. This consists of replacing original saturation-dependent functions on a certain scale by fictitious ones that represent the same physical process in a coarser solution mesh. Simplified numerical and analytical models can be used to construct pseudofunctions. Analytical methods are suitable when simplified assumptions are valid. Coats et al.2 derived pseudofunctions for vertical-equilibrium conditions based on gravity/capillary equilibrium. Hearn3 extended this procedure to noncommunicating layers. Jacks et al.4 introduced space- and time-dependent functions to overcome the rate limitations of the vertical pseudos. To obtain these dynamic functions for each coarse block, it is necessary to run numerical models in a section of the reservoir. Jacks et al. proposed a method based on simulation of 2D cross sections that generates a set of pseudorelative permeability curves representing each column and runs the final model in a 2D areal model. Emanuel and Cook5 extended the pseudorelative-permeability-function concepts to fit vertical performance of individual wells. Using a similar technique, they proposed well pseudos for well completions in the coarse grid. With examples of different completion schemes, they showed that the proposed procedure works for almost all cases presented. Kyte and Berry1 proposed the most common method to calculate dynamic pseudocurves. They developed a method based on Darcy's law to calculate pseudofunctions that is considered to be an extension of Jacks et al.'s4 work and includes pseudocapillary pressure curves. Despite the fact that their method is popular and used as a reference, it does not give good results in strongly heterogeneous media and some inconsistencies, such as negative or infinite values of relative permeability, can occur. On the basis of the Kyte and Berry approach, Lasseter et al.6 presented a multiscale upscaling method suitable for heterogeneous reservoirs. Using some particular reservoir permeability distributions, they showed how reservoir heterogeneities at small, medium, and large scales influence ultimate recovery and how they affect the multiphase behavior. Lasseter et al.'s proposed pseudofunction-generation process begins at the laboratory scale, and the next largest scale can be achieved by replacing effective properties determined at the previous scale. Starley7 presented a procedure based on material balance to derive pseudorelative permeability curves with application to 2D problems. The method is similar to that of Jacks et al.4 and focuses on matching fluid fluxes between interfaces of a reference fine-grid model and a coarse-grid areal model. Their method includes a dispersion-control scheme to offset numerical dispersion and works only for the specific displacement process for which it was derived. Kossack et al.8 described a multistep scaleup process to consider several scales of heterogeneities in two-phase, incompressible displacements. Three geological descriptions of heterogeneities (homogeneous, layered, and random) and various groups of fluid-flow regimes were tested. They ran extensive numerical experiments to verify the effects of different flow regimes on the pseudofunction curves in the three geological descriptions. As in Lasseter et al.,6 Kossack et al.'s pseudofunctions did not consider gridblocks adjacent to wells and they used the Kyte and Berry1 method in their derivation. Stone9 was the first to use the average total mobility to avoid calculating phase potential on the coarser grid (as required by the Kyte and Berry method). He introduced a fractional-flow formula instead of calculating the flow terms by Darcy's law. His method can be applied even to noncommunicating layers. Hewett and Berhens10 and Beier11 proposed other methods based on averaged total mobility. Alabert and Corre12 presented an approach, covering three-phase flow, to deal with 3D models of geological heterogeneity generated by geostatistical conditional simulation techniques.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractReservoir simulation can be a cost-effective tool for helping to optimize the development scheme and minimize economic risk for practically any hydrocarbon reservoir. Simulation of giant deepwater fields can require an increased level of model sophistication, as in many cases there are multiple reservoirs, and planning for a large number of production and injection wells connected to various platforms over large distances. Risk analysis is important, as much of the development planning is based on a limited acquired database. This extended abstract presents a summary of the modeling techniques employed for such a field: Marlim Sul, offshore Rio de Janeiro, Brazil.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince the discovery of the Garoupa