Impairment of Fracture Conductivity in the Eagle Ford Shale Formation
- Jesse Guerra (Texas A&M University) | D. Zhu (Texas A&M University) | A. D. Hill (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference and Exhibition, 24–26 January, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 2.4 Hydraulic Fracturing, 1.6 Drilling Operations, 1.2.3 Rock properties, 5.1 Reservoir Characterisation, 3 Production and Well Operations, 5.1.1 Exploration, Development, Structural Geology, 1.6.9 Coring, Fishing, 1.8.3 Fines Migration, 1.8 Formation Damage, 2 Well completion, 5 Reservoir Desciption & Dynamics, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.4 Shale Oil
- Rock mechanical properties, Fracture conductivity, water-rock interaction
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Fracture conductivity in shale formations can be greatly reduced 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 closure stress, bulk and surface rock mechanical properties, fracture surface topography, fracture surface elemental composition, rock mineralogy, proppant type and concentration, among other factors. This paper presents a study considering several of the aforementioned factors, centered primarily on saline water induced fracture conductivity impairment of the Eagle Ford shale formation and its five vertical lithostratigraphic units.
Laboratory experiments were conducted to investigate the effect of flowback water on fracture conductivity for Eagle Ford shale samples. The majority of 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. 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 and final 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 fracture surface area. 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 in order to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for Eagle Ford formation 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. This is not a large loss in conductivity due to water damage, and suggests that water damage may not be the major cause of the large early decline rates observed in most Eagle Ford shale producing wells.
|File Size||3 MB||Number of Pages||21|
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