Using Wireline Formation-Tester Data for Reservoir Characterization and Connectivity Determination in Ultradeepwater and High-Pressure Wilcox Formation in Gulf of Mexico

Abstract

Abstract Deepwater turbidite reservoirs have always presented several reservoir characterization challenges. Determining the complex architecture of the sand bodies, correlating them across multiple wells in the structure, and defining the sedimentological facies to determine the reservoir vertical communication and boundaries are some challenges in these Gulf of Mexico (GOM) turbidites. Other formation-related challenges of turbidite reservoir exploration and development include understanding reservoir rock quality and compartmentalization, as well as the identification of fluids. Deepwater exploration and development require innovative, cost effective evaluation technologies—technologies that help manage ultradeep and high-pressure environments. Having a detailed description of reservoir properties, fluids characterization, and a determination of the reservoir connectivity are crucial for understanding the reservoir and optimizing the field development plan. This study describes the wireline formation tester (WFT) operations performed in a harsh environment [ultradeepwater subsalt formation (> 32,000 ft) and high pressure (> 25,000 psi)] to obtain pressure data, establish gradients, evaluate vertical connectivity using vertical interference tests (VITs), check for compositional variation in different oil columns, and obtain clean formation fluid samples. Downhole fluid analysis was performed to help ensure the quality of formation samples and determine the fluid compositional analysis in real time during pumpout. To obtain high quality fluid samples while minimizing costs, an innovative technology—namely, a focused sampling probe—was used, eliminating the need for long pumpouts. Representative formation fluid samples were captured from three sample depths in approximately two hours per sample depth with minimum oil-based mud (OBM) contamination (< 5%). All the available openhole log data were integrated to understand the reservoir before running the WFT. Optimizing pressure and sampling depths (most representative intervals) can help reduce uncertainty when determining the number of pressure and sample points in the reservoir. Formation mobility, near-wellbore skin damage, reservoir pressure, downhole compositional fluid analysis, and reservoir connectivity were evaluated in a unique and challenging environment. Reservoir connectivity results from formation testing show good alignment with the presence of fractures and other sedimentary features from borehole image data. A similar methodology can be extended to other deepwater turbidite reservoirs in the GOM.