--> --> Quantifying Organic Porosity and Predicting Estimated Ultimate Recovery (EUR) in the Eagle Ford Formation

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Quantifying Organic Porosity and Predicting Estimated Ultimate Recovery (EUR) in the Eagle Ford Formation


Description Significant shows in the Eagle Ford Shale interval east of the San Marcos Arch ultimately led to exploration and subsequent discovery of the East Texas Eagle Ford Shale play, which now contains over 500 wells. The geologic and engineering components that define the limits of the play are typical: 1) clay content and its effect on mechanical properties and recovery factor; 2) source rock maturity and its effect on hydrocarbon type, reservoir pressure, organic matter porosity and recovery factor; 3) reservoir thickness and internal hydraulic fracture barriers as they are impacted by erosion; and 4) bounding formations and the impacts of depletion. A more detailed delineation of the economic extent of the play required specific input from SEM determined porosity associated with organic matter (PAOM), pore size distribution and the amount of organic matter (confirmed with FTIR (Fourier Transform Infrared Spectroscopy)), from which we could calculate the apparent transformation ratio (ATR) of the organic matter which correlates reasonably well with thermal maturity data from programmed pyrolysis tests across the oil window portion of the play. These inputs in addition to a resistivity constrained height (H) were then used to calculate volumetrics with the assumption that the organic matter porosity is oil-wet and that oil saturation is 100%. The test of the geologic model using these SEM imaging inputs was supported by significantly better correlation to Estimated Ultimate Recovery (EUR) calculations than was achieved using Gas Research Institute (GRI) calibrated petrophysics. Key to using SEM imagery for data field wide was the ability to perform the evaluation on drilling samples from the laterals, keeping the costs down relative to evaluating full and side-wall core. Applications Applications include determining accurate in-place oil and gas volume. Other applications are to improve predictive geologic models that will provide input into predictive reservoir simulation models. Results and Conclusions There is good agreement between traditional LECO TOC, FTIR TOC, programmed pyrolysis and ATR. Resulting volumetrics reflect less effective porosity than seen from GRI calibrated petrophysics which will require adjustments to area, saturation, reservoir thickness, recovery factor. Technical Contributions Illustration of how SEM based PAOM and ATR data on drill cuttings from horizontal wellbores can be used to estimate bulk volume hydrocarbon in-place.