Much has been written about carbonate reservoir complexities, heterogeneity, and data integration at different scales. However, there are not many published examples that show a comparison of producibility modeling predictions and actual field results that include data from core, advanced openhole well logs, formation testers, and drillstem tests.In this study, we present the integration of data and measurements from advanced technologies to evaluate reservoir heterogeneity of carbonate formations on multiple scales. Quantitative textural analyses based on a comprehensive suite of petrophysical logging measurements were integrated with core data and formation testing data to characterize hydrocarbon/water transition zones and formation permeability and producibility. The offshore carbonate reservoir studied is composed of limestones and dolomites. Despite the inherent chemical complexities and hidden modes of origin, dolomites often exhibit favorable reservoir quality with high porosity and permeability properties. For this reason, E&P companies continue to predict where drilling targets are most likely to encounter these sweet spots.Traditional permeability correlations are not effective in these systems, leading to overdependence on porosity-based reservoir descriptions to predict fluid flow. Using nonparametric regression, we have established a relationship between permeability and porosity from logs that are available fieldwide. Subsequent integration of this data with interval pressure transient test data in zones selected based on the observed rock heterogeneity enables further optimization of the final permeability correlation. The descriptions of the field examples confirm the success of this integrated approach and include the planning, real-time monitoring, and final validation of permeability and anisotropy at different scale during the exploration phase of a field.Selecting the well locations for development using the proposed approach has proved valuable for improving field development practices. The results have led to enhanced reservoir characterization based on flow (permeability) and storagecapacity analyses (porosity partitioning), and a better understanding of the reservoir heterogeneity at different scales; the results have been used to improve drillstem test designs and reservoir production strategies.

In 2007, a new Independent Brazilian Oil and Gas company acquired 21 exploration offshore blocks, increasing its portfolio up to 29 blocks by March 2009. Ambitious exploration and production goals were set, such as Drilling Commencement by Q3 2009, Minimum Well Drilling Commitments in four Basins by 2010/11, Initial Development in the Campos Basin and First Oil by 2012. The first three initial goals have already been met and the fourth one is well online to be met as expected with the FPSO already in the Brazilian coast. One of the key elements to reach these objectives is recognized to be the implementation of a focused innovative decision workflow, supported by a real time monitoring process from a cross-disciplinary Operations Support Center (OSC). This paper presents this innovative work scheme, based on a collaborative working environment between the operating and service companies during the well testing operations, with the most advanced monitoring and interpretation tools. It includes a concrete field case which resulted not only in improved risk identification, prevention and mitigation, but also in operational performance optimization. This case was a horizontal open hole test of 1080 mts with 90 deg deviation. The real-time collaboration resulted in significant rig time savings, mitigation of unexpected events consequences, and delivery of higher productivity comparing similar wells results in the area. This innovative decision workflow implemented in Brazil is considered as a high-technological reference model for operating companies, locally in Brazil and others around the world, to achieve success during challenging Well Testing operations.

Separators have a proven track record and are widely used in well testing operations. However, their range of applications is relatively narrow and they can encounter limitations with fluids for which separation is an issue. For example, in wet gas wells, when the liquid volume is small compared to the gas, or the gas and liquid are foaming, it is difficult to separate properly the phases, especially at high flow rates where the retention time in the separator vessel may be too short. Inefficient separation results in wrong measurements, which can not only have significant consequences for the assessment of commerciality of a new field, but also have a negative environmental impact if the burning process is also adversely affected, resulting, for example, in production of black smoke or imperfect burning leading to hydrocarbon discharge in the environment.This paper describes a well test in a deepwater well offshore Brazil. To be able to accommodate different production scenarios, two separators and a multiphase meter were used to measure the flow rates. During the test, the comparison of the flow rates from the multiphase flow meter and those reported by the separator made possible the identification of some carryover in the separator at high choke setting. When the choke size was increased, the separator gas rate increased while the liquid rate dropped at the separator, resulting in a very low condensate to gas ratio (CGR). The multiphase meter on the other hand, reported a constant CGR. At the end of the test, the same choke setting was used for a short period of time to confirm the behavior. The same observations could be made on the rates and a small amount of liquid could be seen in the gas flare. The final proof came from the analysis of the downhole samples which confirmed the CGR measured with the multiphase meter.The consistent results from the multiphase meter make it ideal to validate the flow rate measurements from the reservoir and improve the burning efficiency reducing the HSE risks associated with well test operations.