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Ultra low permeability rocks such as shales exhibit complex fracture networks which must be discretely characterized in our reservoir models to evaluate stimulation designs and completion strategies properly. The pressure (Darcy’s law) and composition driven (Fick’s law) flow mechanisms when combined result in composition, pressure and saturationdependent slippage factor. The approach used in this study is to utilize pressure-dependent transmissibility multipliers to incorporate apparent gas-permeability changes resulting from multi-mechanism flows in commercial simulators. This work further expounds on the effectiveness of the theory by presenting a descriptive analysis between two commercially utilized numerical simulators. The applicability of dynamic slippage as an effective flow mechanism governing gas flow mechanisms within the computational environment of two different simulators is attempted in this analysis. Results indicate that slippage-governed flow in modelling shale reservoirs should not be ignored.
Ultra low permeability rocks such as shales exhibit complex fracture networks which must be discretely characterized in our reservoir models to evaluate stimulation designs and completion strategies properly. The pressure (Darcy’s law) and composition driven (Fick’s law) flow mechanisms when combined result in composition, pressure and saturationdependent slippage factor. The approach used in this study is to utilize pressure-dependent transmissibility multipliers to incorporate apparent gas-permeability changes resulting from multi-mechanism flows in commercial simulators. This work further expounds on the effectiveness of the theory by presenting a descriptive analysis between two commercially utilized numerical simulators. The applicability of dynamic slippage as an effective flow mechanism governing gas flow mechanisms within the computational environment of two different simulators is attempted in this analysis. Results indicate that slippage-governed flow in modelling shale reservoirs should not be ignored.
The Barnett Shale success in the 90's has led to a significant amount of focused work on fracturing and its related aspects. The work included understanding its nuances, to be able to design the treatments better, and pump them with enhanced efficiency. Production from these completed wells is highly dependent on both the characteristics of proppants being placed, as well as those of the reservoir being treated. Fracturing leads to an interaction between the minerals of the proppants, formation and the fluids. Incompatible chemical interactions between minerals of the proppants, formation and fracturing fluids lead to precipitations which reduce porosity. Under in-situ conditions, these interactions further facilitate the phenomenon of geo-chemical diagenesis as a result of which rapid loss of fracture conductivity is observed. The diagenesis process includes mechanisms such as diffusion, temperature induced dissolution, precipitation in the pore space, along with chemical reactions at the fracture surface. These mechanisms lead to a reduction in the width and hence, the permeability of the created fracture. Proppant pack permeability reduction is presented in this paper through a mathematical model, which simulates fluid-mineral reactions in the created hydraulic fracture. The model involves solving the diffusion and precipitation equations for each component to simulate the changing porosity and permeability over time. These coded partial differential equations are combined with the reactions occurring at the surface. Further, this work studies the impact of this reduction on the productivity of a well completed in shale reservoir, followed by a sensitivity study of critical parameters. This work will help in a better understanding of reactions occurring within the fractures and their effect on the loss of fracture conductivity. With India looking at developing its shale plays, this work also includes possible issues that could affect this development.
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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