Carbonate reservoirs contain expressive part of the world oil reserves. The exploitation of these resources, however, presents several challenges mainly associated with their complex pore geometry, large scale variation in permeability and sometimes unfavorable wettability. These challenges can become more significant when we move to a deep offshore environment. As offshore projects need to be planned well in advance, due to the lack of room in the platforms for future expansion, the pioneer application of EOR methods needs to be considered from the conceptual stage of the development.This paper addresses the approach used to design the development basis for Lula field, formerly known as Tupi area, in the Pre-Salt Cluster (SBPSC) in Santos Basin, offshore Brazil. It focuses on the strategy of phased development, dynamic data acquisition and actions to add flexibility to the production system and how to manage uncertainties. A comprehensive analysis of the existing uncertainties, such as the reservoir characterization, early water and gas breakthrough, bypassed oil saturation, flow assurance in deep water flowlines and CaCO 3 scale possibility in production wells, favored a phased development concept aiming to mitigate risks.. The approach used to cope with these uncertainties in a Pilot Project as well as in the future development scenarios is presented. Most of the discussion is focused on how to consider feasible Enhanced Oil Recovery techniques through Pilot testing and future implementation in large scale in the field. It comprises the investigation of different recovery processes and first field results, including miscible processes using hydrocarbon gas and CO 2 . To optimize the oil displacement, a water alternating gas (WAG) injection process is also being designed.After one and a half year of extended well test production and the implementation of the first Pilot project in January, 2011, results confirm the decision of providing additional flexibility to the project. Dynamic appraisal proved essential to assess reservoir connectivity, evaluate stimulation methods, support reservoir characterization studies and define aspects related to flow in subsea lines. The first results of the injection of the CO 2 stream, separated from the associated gas in the Pilot project, indicate that the chosen strategy has potential to be a successful one. The continuing production and pressure data monitoring of the WAG implementation in the Pilot, from 2012 on, will provide a more definitive conclusion about the feasibility. Good responses will translate in the EOR expansion to field scale.

The displacement of a given fluid by another in a porous media can occur either in miscible or immiscible conditions. An immiscible displacement happens, for instance, when water displaces oil in a reservoir. It can also occur when the displacing fluid is a gas, if the interfacial tension with the oil is high enough. These processes are usually described by the fractional flow theory, which assumes isothermal flow of two immiscible and incompressible fluids in an one-dimensional, homogeneous porous media; dissipative effects, such as capillary pressure, compressibility and thermal conductivity, are neglected. Miscible floods, on the other hand, can take place in gas-oil displacements when the interfacial tension approaches zero. Common dissipative effects are fingering and dispersion, the former related to mobility ratio magnitudes and the later related to diffusion and velocity contrast commonly caused by the presence of heterogeneities. In miscible displacements through porous media, dispersion is described as the result of diffusion, local velocity gradients, streamlines dimensions in heterogeneous regions, and mechanical mixing into pores. The present work discuss these concepts and relate them to data from an actual deep offshore field. Estimates of field dispersivity by history matching tracer production profiles are based on the analytical solution for the convection-diffusion equation. Gas tracers injected and produced from wells located in the field area were evaluated assuming miscible displacement. The estimated dispersivity allowed the evaluation of mixing/spreading zones. The solution for intermittent tracer injection was used to history match tracer production data. Results shows the scale dependence of the dispersivity, which depends upon the distance and degree of heterogeneity between wells. The field scale dispersivity obtained by history match was coherent with numerical dispersion observed in a field scale numerical model. They were also compared against literature data (laboratory and field scale) in a log-log plot denoting a good agreement of present data with literature.

This paper presents the successful history of Lula NE Pilot Project, a challenging megaproject with an aggressive time-driven schedule, faster than industry average, that demanded new technology development in a scenario of uncertainty. The area is part of the supergiant Lula field, located in the pre-salt region of Santos Basin, Southeast Brazil, 300 km off the coast of Rio de Janeiro state, in 2000 m water depth. It is a joint venture with Petrobras as the Operator, and BG E&P Brasil and Petrogal Brasil as partners. The project was designed as a Pilot aiming to test some new concepts for the production development in the pre-salt area. In terms of subsea gathering system, an innovative concept was deployed, combining flexible flowlines lying on sea floor, with rigid steel catenary risers (SCR) supported by a buoy positioned 250 m below sea level. The drainage plan considered eight oil producers, some of them with intelligent completion, one gas / CO2 injection well and five water alternating gas (WAG) injectors (two subsea WAG manifolds were also installed). A balanced approach between data acquisition and facilities flexibility made possible to face the many reservoir and production uncertainties. Details of the development concept will be discussed, as well as the main results obtained so far, highlighting the strategies adopted in order to mitigate risks and the influence of the acquired information to the following projects in the area. The chartered FPSO Cidade de Paraty started production in June 2013, with an oil capacity of 120,0 bpd, and a gas plant able to process up to 5 million m3/d of gas with 35% content of CO2. Despite all challenges faced, the project was delivered on time, with plateau attained in September 2014.

This paper addresses the use of the Spearman rank coefficient, a nonparametric statistical method, to estimate lateral autocorrelation and permeability trends. This approach provides an alternative to interference tests considering only production and injection rates. The objectives of this work are to validate this technique, point out its advantages/limitations and show results from its application to a field. We performed a set of numerical experiments using a flow simulator and different synthetic permeability fields. The results highlight the dependence of the proposed method on reservoir parameters. The method can indicate the presence of transmissibility barriers, permeability anisotropy and, in some situations, range anisotropy. Next, we present a field case to demonstrate the application of the method. The Canto do Amaro field, located in the Potiguar basin, Brazil, is chosen because of a small well spacing and a previous comprehensive reservoir characterization study using geostatistics. The results obtained provide a better understanding of how rank analysis can be used as an effective reservoir characterization tool. Introduction A major source of information in a developed field comes from the widely available measurements of production and injection rates at existing wells. If this information could be used as a reservoir characterization tool to indicate anisotropy and communication trends, progress could be achieved in reservoir management without the cost of additional data. This paper aims to provide more insight into such an approach. The results were obtained from two different investigations. First, we performed a s t of numerical experiments using a flow simulator and different synthetic permeability fields. Then, we chose a field case to illustrate a practical application. Background The advantages of using data from interference tests are well described in the literature(1). This type of test can provide information on reservoir properties that cannot be obtained from ordinary pressure buildup or drawdown tests. The well-test analysis approach needs production and pressure data to estimate the reservoir properties and requires a well intervention. An alternative way to perform interference tests would onsider only the analysis of injection and production fluid rates. If successful, this approach would be attractive since the fluid rate information is widely available. Parametric statistics compare the statistic from a sample with an assumed population parameter; usually the statistics are the mean and variance of a distribution. Nonparametric statistics, however, do not involve any assumption about the distribution of the population. Therefore, the approach is parameter free and its required assumptions are fewer and less restrictive than those associated with parametric tests(2). This feature makes its use appropriate to data that do not fit a specific distribution or where the distribution type is unknown. One additional advantage is that nonparametric techniques can be used with scores that are not exact in any numerical sense, but which, in effect, are simple ranks. ranks. Journel(3) presented one of the first applications of nonparametric statistics in the petroleum industry. He introduced a nonparametric Kriging approach in which the data were described through their rank order.

This paper addresses the use of the Spearman rank coefficient, a nonparametric statistics, to estimate lateral autocorrelation and permeability trends. This approach provides an alternative to interference tests considering only production and injection rates. The objectives of this work are to validate this technique, point out its advantages/limitations and show results from its application to a field.We performed a set of numerical experiments using a flow simulator and different synthetic permeability fields.. The results highlight the dependence of the proposed method on reservoir parameters. The method can indicate the presence of transmissibility barriers, permeability anisotropy and, in some situations, range anisotropy.Next, we present a field case to demonstrate the application of the method. The Canto do Amaro field, located in the Potiguar basin, Brazil, is chosen because of a small well spacing and a previous comprehensive reservoir characterization study using geostatistics. The results obtained provide a better understanding of how the rank analysis can be used as an effective reservoir characterization tool.