Vladislav Achourov

Real Time Integration of Reservoir Modeling and Formation Testing

The increasing complexities of newly discovered reservoirs coupled with the increasing cost of field development mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consuming and require well-organized cross-disciplinary integration between geoscientists. Such models and processes are not well suited to be used and updated during formation-evaluation acquisition phases of field development. In this paper, a more accessible approach is proposed and demonstrated. The existing fluids model is combined with the current geologic model to construct an accurate representation of key features of the reservoir. This model is then used to predict data for a wireline formation sampling and testing tool (WFT), with emphasis on downhole fluid analysis (DFA). In this process, current reservoir understanding is tested by direct measurement in real time. If differences are uncovered between predicted and measured log data, the WFT tool is in the well, and measurements can be made to uncover the source of the error. In this paper a workflow is demonstrated in which WFT DFA and pressure/volume/temperature (PVT) lab reports were used to build a fluid model after the first exploration well data was acquired. This model was then used to predict fluid properties and WFT DFA logs for a subsequent well intersecting nominally the same compartment. These DFA predictions presumed fluid equilibrium and flow connectivity. Real-time comparisons were made of predicted and measured pressures, fluid gradients, contacts and DFA data obtained from the WFT logging run. Agreement of predicted and measured log data indicates that fluid properties and reservoir connectivities used for the modeling are correct. If predictions disagree with measurements, the acquisition program can be altered in real time to ensure sufficient data are acquired to understand the reservoir model inaccuracies. During the WFT logging job, this predictive model enabled validation of critical WFT data. This process also allowed testing of the reservoir connectivity. It was discovered that either compartmentalization or lateral disequilibrium of the fluids in the reservoir exists. Interpretation of the DFA data suggested that a subtle lateral disequilibrium exists, and the assumption of reservoir connectivity is supported.

DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity

In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.