Cristiano L. Sombra

Challenges and New Technologies for the Development of the Pre-Salt Cluster, Santos Basin, Brazil

Pre-salt carbonate reservoirs from Santos Basin represent a great opportunity and probably the most important recent oil discovery. Tupi area (estimated to have recoverable volume of 5 to 8 bboe), which is the most known amongst several other leads in the cluster, is going to be a great insight for the production project. From the production point of view, this new frontier has technological challenges that are being addressed by PETROBRAS and partners. Special attention is being dedicated to anticipate solutions to potential problems. This will require a balance between innovative and field proven solutions. This paper addresses the most critical points, where Petrobras is making a great R&D effort, which are: Well technology, where casing stability, well cost and productivity are addressed, in a scenario of water depths beyond 2,200m, target depths greater than 5,000m, crossing salt layers that can reach 2,000m in thickness. Poorly known microbial carbonate reservoir, heterogeneous in vertical profile, spread over very large areas, with wettability concerns, requiring careful evaluation of the performance of the waterflooding method and EOR. Wax deposition, due to low temperature in the ocean bottom, imposing limitations to the subsea layout. Gas processing and exporting technologies concerning environmental issues: CO2 compact removal units aiming the minimization of emissions to the atmosphere. Production units placed in more than 2,000m water depth, with oceanic conditions quite severe and dealing with high CO2 content stream. These challenges deserve all Petrobras attention, but also count with the confidence in achieving good technological solutions, supported by the history of successful developments of the company. Introduction The history of success built by Petrobras in deep water Brazilian coast – mainly Campos Basin – was largely supported by successive discoveries of heavy oil in turbidite sandstones, step by step towards gradually deeper and deeper water depths (Carminatti et al., 2009). The Pre-salt discoveries of Santos Basin represent discovery of huge volumes of light oil (28 to 30 degrees API), with high gas content, in a very short time span, close the most important consuming centers in Southeastern Brazil, and formation tests in the first wells have presented very high flow rates with no indication of barriers. All are excellent news, although PETROBRAS and partners recognize that the Pre-salt of Santos Basin represents a challenging scenario: ultra-deep water (greater then 2,000 meters), deep carbonate reservoirs (deeper than 5,000 meters), spread over very large areas, with high gas-oil ratio (GOR in Tupi area greater than 200 m/m), CO2 content (8-12% in Tupi), high-pressure and low temperature, laying immediately bellow a thick salt layer (more than 2,000 meters of salt), located around 300 km from the coast, with oceanic conditions more severe than Campos Basin. This scenario demands using sometimes present day technology in the limit, and other times, adaption and development of technologies specific for such conditions. This paper addresses the most critical points to the development of production in the Pre-salt of Santos Basin, where Petrobras is making an R&D effort to develop and qualify new technologies, including well technology, reservoir technology, flow assurance, gas processing and exporting technologies, and production units. Additionally, the paper discusses briefly how PETROBRAS has organized its structure to face these technological challenges, including the creation of a technological program – PROSAL – focused on Pre-salt objectives.

A multi-scale approach to improve reservoir characterization and forecasting: the Albacora Field (deep-water offshore Brazil) study

The Upper Albian Namorado Sandstone is one of the reservoirs of the Albacora Field, located in the Campos Basin, deep-water offshore Brazil. It is a sand-rich turbidite system where the most important controls on permeability are calcite cementation, thin beds of non-reservoir lithologies and some north–south trending faults. A major multidisciplinary reservoir characterization project was conducted to improve the reservoir description using all available data. In this paper, we focus on how the effect of rock heterogeneities were represented in the fluid flow model and on the performance obtained from this model. The basic idea was to define a hierarchical model of facies established on the basis of three main work scales: porous systems (thin sections and core sample scale); composite facies (whole core and log scale); and seismic facies (interwell to field scale). An up-scaling technique, based on the geopseudo concept, was used to generate the effective petrophysical properties for the fluid-flow simulation model. A Markov–Bayes geostatistical simulation method was applied in facies stochastic modelling. The sophisticated model that was built allowed very fast history matching.

Flow Simulation Study of the Namorado Sandstone (Albacora Field, offshore Brazil) Accounting for Scaling of Petrophysical Properties

This 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 MarkovBayes 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.