Fractal and power law distributions have been found in the past to be useful for modeling some reservoir properties following the assumptions of constant shape and self-similarity. This study shows, however, that pore throat apertures, fracture apertures, petrophysical and drill cuttings properties of unconventional formations are better matched with a variable shape distribution model (as opposed to constant shape). This permits better reservoir characterization and forecasting of reservoir performance. Pore throat apertures, fracture apertures, petrophysical properties and drill cutting sizes from tight and shale reservoirs are shown to follow trends that match the variable shape distribution model (VSD) with coefficients of determination (R2) that are generally larger than 0.99. The good fit of the actual data with the VSD allows more rigorous characterization of these properties for use in mathematical models. Data that could not be described previously by a single equation can now be matched uniquely by the VSD. Examples are presented using data from conventional, tight and shale formations found in Canada, the United States, China, Mexico and Australia. In addition, the study shows that the size of cuttings drilled in vertical and horizontal wells can also be matched with the VSD. This allows the use of drill cuttings, an important direct source of information, for quantitative evaluation of reservoir and rock mechanics properties. The results can be used for improved design of stimulation jobs including multi stage hydraulic fracturing in horizontal wells. This is important as the amount of information collected in horizontal wells drilled through out tight formations, including cores and well logs, is limited in most cases. It is concluded that the VSD is a valuable tool that has significant potential for applications in conventional, low and ultra-low permeability formations and for evaluating distribution of rock properties at the micro and nano-scale.
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.
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