A Comparative Study of the Effects of Clay Content on the Fracture Conductivity of the Eagle Ford Shale and Marcellus Shale Formations
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2017, Unconventional Resources Technology Conference (URTeC). Fracture conductivity in shale formations can be significantly impaired due to water-rock interactions. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration due to fracture surface spalling and failed proppant particles. Fracture conductivity is influenced by many factors, however the formation's mechanical properties and mineralogy, or more specifically the clay content and clay type, can have the most significant effects on the resulting fracture conductivity when the fracture surfaces are exposed to water. This paper presents a comparative study on the effects of clay content on fracture conductivity impairment of the Eagle Ford shale and the Marcellus shale formations. Laboratory experiments were conducted to investigate the effect of flowback water on fracture conductivity for Eagle Ford shale and the Marcellus shale samples. The majority of the Eagle Ford test samples were obtained from an outcrop located in Antonio Creek, Terrell County, Texas; while the remaining samples were obtained from downhole core provided by an industry partner. Samples of the Marcellus shale consisted of outcrop samples collected from Elimsport Quarry as well as a site in Allenwood, Pennsylvania. Saline water with a similar chemical composition to the typical field flowback water was utilized. Fracture conductivity measurements were conducted in three stages. In the first stage, dry nitrogen was flowed to ascertain the undamaged initial fracture conductivity. In the second stage, the saline solution was injected into the fracture until steady state behavior was observed. In the third stage, dry nitrogen was once again flowed to quantify the recovered fracture conductivity. Reported mechanical properties from the same outcrop rock samples, consisting of Poisson's ratio and the Brinell hardness number, were considered in this study. Additionally, reported mineralogy obtained using X-ray powder diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained using X-ray fluorescence (XRF) microscopy, and fracture surface topography was obtained using a laser surface scanner and profilometer. Results support findings that bulk and surface mechanical properties influence fracture conductivity, as well as surface topography and related attributes such as abrupt surface changes. Furthermore, the bulk mineralogical composition of the rock and the elemental composition of the rock fracture surface have a significant impact on fracture conductivity when flowing saline water. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for Eagle Ford shale ranging from approximately 4 to 25 % after flowing saline water, when compared to the initial conductivity measured by flowing dry nitrogen before saline water exposure. Similarly, the loss of fracture conductivity observed for the Marcellus shale ranged from approximately 36 to 48% after flowing saline water. Results from this study also suggest that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford shale producing wells, and that in general, other factors such as proppant embedment might also be contributing to the impairment of fracture conductivity in shale formations.
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Proceedings of the 5th Unconventional Resources Technology Conference
