Abstract

In 2014, U.S. crude oil reserves exceeded 39 billion barrels, the fourth-highest on record, and proved reserves of natural gas increased to 388.8 trillion cubic feet, surpassing the record from 2013 (EIA 2015). The Eagle Ford Shale is a primary contributor to the added U.S. proved oil and gas reserves (EIA 2015). Successful exploration and development of the Eagle Ford Shale play requires reservoir characterization, recognition of fluid regions, and the application of optimal operational practices in all regions.

Various approaches have been used to determine which geologic parameters have the greatest influence on Eagle Ford Shale well productivity. Previously, regional statistical studies of production and geologic parameters were employed to analyze the relative importance of depth, thickness, and total organic carbon content on cumulative production. Regression coefficients and P values were examined. Although those studies provided insights to regional controls on Eagle Ford production trends, understanding which geologic parameters have the greatest impact on production performance of individual wells required more detailed simulation models.

Based on the frameworks provided by stratigraphic and petrophysical analyses, a single well compositional model for a representative Eagle Ford gas condensate well was built, and history matching based on production and pressure data was performed. PVT reports were available to simulate phase behavior. Multiple good history matches were obtained by varying a set of uncertain input parameters, such as water saturation, and relative permeability. Porosity and permeability were modeled as functions of pressure to consider reservoir compaction effects. The distribution of parameters from various history match results was plotted, allowing their impacts on the production behavior of the well to be quantitatively correlated and analyzed. This approach was preferred to traditional sensitivity study approaches, where a single parameter is changed each time, and the ranges of the parameters are not guided by historical data. In addition, interactions among the parameters cannot be considered without history matching. Well deliverability was also modeled to optimize the oil production rate by designing appropriate operational parameters.

Hydraulic fracture geometry and reservoir drainage area are the dominant controls on production. Reservoir modeling suggests low bottomhole flowing pressure was the key to optimizing cumulative gas condensate production. Minor changes in porosity significantly impact production Eagle Ford Shale condensate production, whereas production is less sensitive to variations of water saturation and matrix permeability. Concepts and models developed in this study may assist operators in making critical Eagle Ford Shale development decisions, including optimizing individual well performance.

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