Abstract
Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the U.S. Energy Information Administration (EIA) nearly 90% of the oil production growth comes from six tight oil plays. The Eagle Ford is one of these plays and accounts for 33% of the oil production growth with a contribution of 1.3 million barrels per day.
A geological challenge in the Eagle Ford shale is the unconventional fluids distribution: shallower in the structure there is black oil, deeper and to the south condensate appears, and at the bottom dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other reservoirs (e.g. Duvernay shale in Canada).
The above observations led to the key objective of this paper: to identify the main factors that control fluid migration (due to buoyancy of gas in oil) from one zone to another. This was done by constructing a conceptual cross sectional simulation model with NW to SE orientation that allowed the study of fluid migration and distribution throughout one million years while maintaining computational time within reasonable limits.
The input data used for the model were gathered from published work in the geoscience and petroleum engineering literature. Results show that although there is some gas migration through fractures to the top of the structure, fluids in the matrix remained with approximately the same original distribution. This fluid migration through fractures could be responsible for higher initial gas production in some oil wells in the top of the structure.
Results show that ultralow permeability, low porosity, and low natural fracturing are the main restrictions for fluid migration in the Eagle Ford shale.
