Book Description

A large proportion of the hydraulic fractures created during a hydraulic fracturing treatment remain unpropped after hydraulic fracturing despite the significant quantities of proppant injected in the process. These fractures either have a fracture width smaller than the size of the proppants, or are too far away from the wellbore where proppant cannot reach. Their presence has been demonstrated and corroborated by multiple independent sources of evidence such as flowback, production and microseismic data. These unpropped fractures present a huge potential for production enhancement, since they possess a very large contact area with the reservoir. Unfortunately, this potential flow area is closed by the closure stress during production. Without the presence of proppants, unpropped fractures are expected to behave differently from propped fractures. In this study, fracture conductivities of unpropped fractures in shales are measured with preserved Eagle Ford and Utica shale cores to better understand their closure behavior, in particular those after exposure to fracturing fluids. The unpropped fractures exhibit fracture conductivities 2 to 4 orders of magnitude lower than those of propped fractures, and are more sensitive to closure stress. Plastic deformation is found to dominate the closure process, and strong hysteresis occurs in unpropped fracture conductivity with a 70-80% reduction after a loading-unloading cycle of closure stress. Exposure to water-based fracturing fluids reduces unpropped fracture conductivity by shale softening or fines production. Unpropped fracture conductivities also appear to be sensitive to shale mineralogy, which affects the shale mechanical properties and shale-fluid interaction. A numerical model is developed to simulate the closure of unpropped and natural fractures, and to compute their corresponding fracture conductivity. A conjugate gradient algorithm and fast Fourier transform technique are incorporated to dramatically enhance the computation efficiency. Plastic deformation and deformation interaction among asperities, ignored in some previous models, are considered and shown to play an important role in the closure process. The model is validated against analytical solutions and experiments, for both elastic-only and elastoplastic scenarios. The compliance of unpropped fractures is demonstrated to be sensitive to the roughness and hardness of fracture surfaces, while less affected by Young’s modulus. The new model is also capable of simulating closure of heterogeneous fracture surfaces. More plastic deformation and lower fracture conductivity is measured when surfaces with high clay content are used. Given the same mineralogy, the mineral distribution pattern shows a smaller impact on the closure behavior. The possibility of employing acid fracturing to stimulate unpropped fractures is also explored. The acid-etched topography of shale fracture surfaces is found to be dependent on both the content and distribution of the carbonate minerals. Shales with a high carbonate content (over 60 wt%) generally tend to develop rougher acid-etched surfaces. However, more carbonate content does not always necessarily lead to increased etched roughness. High etched roughness is more likely developed from a blocky, rather than scattered, distribution of carbonate minerals. A new experimental method, the “half-core approach”, is formulated to address the challenge caused by shale heterogeneity in experimentally evaluating and comparing fracture performance. The half-core approach splits one shale core into two half cores, which are then subjected to treatments of interest independently, followed by assemblage into individual full cores with a spacer for fracture conductivity measurement. The half-core approach is effective in creating a baseline with reduced sample variation among shales to improve evaluation of fracturing fluids. Similar mineralogy and mechanical properties are found between half-cores among preserved shale samples spanning a wide range of mineralogy from Barnett, Eagle Ford, Haynesville and Utica shales. By applying the half-core approach, acid fracturing is systematically benchmarked against brine with Eagle Ford shales categorized into low (below 40 wt%), medium (40-70 wt%) and high (over 70 wt%) carbonate content. Compared to brine exposure, non-uniform acid fracturing enhances unpropped fracture conductivities for shales for a wide range of carbonate contents, while uniform acid fracturing generally leads to lower fracture conductivities due to shale softening. The unetched zone in non-uniform etching reduces shale softening and creates a surface topography that enhances fracture flow. Channels are more likely to form in carbonate-rich shale (over 70 wt%). Development of channels substantially increases the unpropped fracture conductivity, and reduces the hysteresis of unpropped fracture conductivities to closure stress. The presence of carbonate veins is found to promote the development of non-uniform etching.