Abnormal Viscosity and Other Implications of Reservoir Connectivity Inferred from Reservoir Fluid Geodynamics: A Case Study from Deepwater Gulf of Mexico

Abstract

Abstract Reservoirs are often compartmentalized owing to the presence of barriers including structural flow barriers resulting from geodynamic processes such as faulting, or depositional stratigraphic barriers such as shale breaks. Concurrent with structural geodynamics, reservoir fluid geodynamics (RFG) processes take place such as fluid mixing, hence defining fluid systems that respond to their evolving reservoir container. RFG processes account for reservoir fluid compositional variation, spatial redistribution, and phase change from time of charge to present day. Accordingly, hydraulic connectivity directly affects the distribution of fluid properties, while presence of baffles can lead to poor mixing of hydrocarbon charges, and variable reservoir conditions across compartments impact the evolution of similar source oil, leading to significant variations of present-day oil properties, such as potentially viscous oil. Thus, reservoir connectivity implications are critical and require thorough investigation. We study RFG processes that explain the reasons behind varying oil compositions and properties within and across different reservoir compartments. Furthermore, we explore how to infer fluid implications with wireline logging measurements. By analyzing chemical and geochemical measurements of reservoir fluids, we determine the current state of thermodynamic equilibration. Asphaltene gradients are analyzed by integrating downhole fluid analysis (DFA) measurements and Flory-Huggins-Zuo's equation of state (FHZ EoS) with its reliance on the Yen-Mullins model of asphaltenes. While equilibrated asphaltene gradients imply connectivity, ongoing RFG processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. We also examine pressure-volume- temperature (PVT) reports, pressure surveys, and well logs and account for viscosity variations and the origin of viscous oil in terms of hydrocarbon maturity and asphaltene migration. The reservoir considered in this study is located in the deepwater Gulf of Mexico; the trap is a large anticline segmented by many normal faults leading to substantial compartmentalization. Some complexities in asphaltene gradients and viscosities are noted and explained: asphaltene behavior in one well is fundamentally different from 3 adjacent wells, another well shows lower asphaltene content than 2 adjacent shallower wells, and asphaltene cluster formation with corresponding large gradients in 2 wells causes high viscosities. Fault- block migrations are detected in 3 different regions penetrated by 7 wells; fault throws are quantified (950, 720, and 720 feet), where we use asphaltene behavior to deduce original field and fluid structures before faulting. From analysis with the FHZ EoS, we conclude that oil charge occurred prior to faulting for several fault blocks. Similar asphaltene behavior across fault blocks indicates that faults between corresponding blocks act as seals. Additionally, we suggest improvements to the geologic model that reflect sub- seismic/unresolved faults and relate hydraulic connectivity to reservoir quality. Connectivity implications on oil chemistry are quantified as part of the study. Invaluable insights stem from relating geological and fluid complexities. Through the case study, we relate dynamic (e.g., formation-testing measurements) and static data (e.g., well logs), where significant applications include inferring fault block migrations, sequence of faulting and charging, viscosity variations, and enhancing geological characterization.