Impairment of Fracture Conductivity in the Eagle Ford Shale Formation
- Jesse Guerra (Texas A&M University) | Ding Zhu (Texas A&M University) | Alfred D. Hill (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2018
- Document Type
- Journal Paper
- 637 - 653
- 2018.Society of Petroleum Engineers
- fracture conductivity, water damage, shale formation
- 3 in the last 30 days
- 487 since 2007
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Fracture conductivity in shale formations can be greatly reduced because of water/rock interactions depending on the properties of formation rock and reservoir/fracture fluids. The mechanisms of water damage to fracture conductivity include clay swelling, surface softening, excessive proppant embedment, and fines migration caused by 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, and 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 and quantify the effect of flowback water on fracture conductivity for samples of Eagle Ford Shale. The majority of test samples were obtained from an outcrop in Antonio Creek, Terrell County, Texas, while the remaining samples were obtained from downhole core provided by an industry partner. The different lithostratigraphic units present in the Eagle Ford Shale formation were accounted for. Saline water with a chemical composition similar to that of the typical field flowback water was used.
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 (BHN), were considered in this study. In addition, reported mineralogy obtained by use of X-ray-diffraction (XRD) microscopy was taken into consideration. The elemental composition along the fracture surface was obtained by use of X-ray-fluorescence (XRF) microscopy, and fracture-surface topography was obtained by use of 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 effect on fracture conductivity when flowing saline water to simulate flowback. Clay content was observed to directly influence fracture conductivity. The results of this study show a loss of fracture conductivity for the Eagle Ford Formation ranging from approximately 4 to 25% after flowing saline water, compared with the initial conductivity measured by flowing dry nitrogen before saline-water exposure. This is not a large loss in conductivity caused by 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.
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