Field studies demonstrate low flowback efficiency determined by volumetric analysis of injected and recovered fracturing water. However, the reasons for inefficient water recovery, and its impact on short-term and long term production are poorly understood. Furthermore, volumetric water analysis is not sufficient for determining the source of recovered water and the true load recovery. This paper aims at understanding how flowback efficiency is related to the imbibition process, presence or absence of natural fractures, and the complexity of induced fracture network. We interpret the flowback rate and salt concentration, measured from several multi-fractured horizontal wells recently completed in different members of the Horn River basin. We also measure and analyze water imbibition and salt diffusion rate in actual cores drilled from the same shale members. The wells are classified into those with 1) low water and high gas production, 2) high water and low gas production. This classification is explained by lab imbibition data and possible fracture patterns. Furthermore, the flowback salt concentration change is explained by the diffusion data measured in the laboratory. This systematic study provides a practical database for understanding the factors impacting the water recovery that will potentially help the operators to optimize the flowback operations, and obtain useful information about the induced fracture network.
Tight reservoirs stimulated by multistage hydraulic fracturing are commonly characterized by analyzing the hydrocarbon production data. However, analyzing the available hydrocarbon production data mainly determines the fracture-matrix interface. This analysis is not enough for a full characterization of the induced hydraulic fractures. Before putting the well on flowback, the induced fractures are occupied by the compressed fracturing fluid. Therefore, analyzing the produced fracturing fluid should in principle be able to characterize the induced fractures, and complement the production data analysis.We develop a rate transient model for describing the fracturing fluid flowback. We also make various diagnostic plots for understanding the flowback behavior of three fractured horizontal wells. The diagnostic plots indicate three separate flowback regions. In the first region, water production dominates while in the third region hydrocarbon production dominates. In the second region, water production drops and hydrocarbon production ramps up. In general, we observe a linear relationship between rate normalized pressure (RNP) and material balance time (MBT) for the three regions. However, the proposed model can only describe the response of the first region. We successfully determine the hydraulic fracture permeability by history matching the early time flowback data. We conclude that the flowback analysis can complement the production data analysis for a comprehensive fracture characterization. The presented study encourages the industry to start careful measurement of the rate and pressure data immediately after putting the well on hydraulic fracture flowback.1. The early-time oil or gas production data is usually unavailable or of low quality for history matching. 2. The induced fracture network is initially filled with compressed fracturing fluid not hydrocarbon. Therefore, analyzing the hydrocarbon data for determining the fracture storage capacity can be misleading. 3. Production data analysis does not account for the fractures, which are filled with water and do not contribute to the hydrocarbon flow.This paper hypothesizes that analyzing the fracturing fluid flowback can complement analyzing the hydrocarbon production data. Flowback analysis requires representative mathematical models for history matching the pressure and flow rate measured during the flowback operation. To the best of our knowledge, there is no representative mathematical model in the open literature for interpreting the flowback data of fractured horizontal wells.The fracture-matrix interface and fracture half-length are usually determined by analyzing the hydrocarbon production data. The dual porosity model has been extended for analyzing the fractured horizontal wells [1,6]. The available production data mainly match with the late transient part of the type curves, which relates to the fluid transfer from the matrix into the fracture.
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