A series of subsurface reservoir and geological properties are reviewed, specific to the Eagle Ford Shale of south Texas and compared with production trends. Currently, an area in excess of 7 million acres has been tested for Eagle Ford production potential by hydraulically fracture-stimulated, horizontal wellbores. The bulk of this area is suitably thick (>125 ft [38.1 m]), organic-rich (>2 wt. % total organic carbon), and attains a thermal maturity consistent with hydrocarbon generation for Type II kerogen (>435°C T_max). Production trends, highlighted by well performance analysis from over 1450 wells, point to a clear differentiation of an optimum fairway comprising a greater population of strong wells. This fairway represents approximately 10% of the aforementioned area. With this in mind, the significance of key geological properties and their heterogeneities are evaluated and discussed. Understanding well performance, and more importantly, the key drivers that govern well performance provide the motivation for this study.

The results of this study highlight the fact that the best performing wells across the play (based upon initial 18-month cumulative production) are located within a narrow 7 mi (11.3 km) wide, SW–NE strike-orientated belt that extends across several counties spanning approximately 140 mi (225.3 km). This fairway in general parallels the ancestral lower Cretaceous shelf edges (Sligo and Stuart City) and is characterized by a thermal maturity window (460–500°C T_max) consistent with wet gas and condensate production. Structurally downdip of these margins the play transitions into dry gas. Moving updip to the north, lower levels of thermal maturity are encountered (i.e., early oil window) that deliver lower volume wells, presumably due to lower levels of kerogen conversion and transformation. Thermal maturity is one of the primary well performance drivers in the play.

Across the central portion of the trend, within the optimum maturity window, local production sweet spots exist that are further delineated by a combination of higher reservoir pressure and the interaction of local depositional patterns that promote above-average accumulations of organic-rich facies. By contrast, a significant proportion of the poorer wells analyzed commonly display much higher values for clay content, even though many of these wells share favorable levels of thermal maturity, reservoir pressure, and moderate organic-richness. The elevated clay content (>30%) and resulting undesirable geomechanical properties restrict well performance. This is likely a function of limited stimulation effectiveness and/or proppant embedment. Clay content is the single most important metric that significantly degrades well performance, even when other parameters are favorable. This degradation can occur over a short distance (2-5 mi [3.2–8 km]) and is independent of most other variables. Wellbore-scale properties such as the occurrence of natural fractures appear to influence early time flow-back profiles, but have a modest influence on long-term well production. These variances represent smaller-scale perturbations that are superimposed upon the broader controls noted earlier.