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The combined application of multi-lateral horizontal drilling and multi-stage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a fraction of the large water volume used in hydraulic fracturing treatments is recovered during flowback operations. The fate of non-recovered water and its impact on hydrocarbon production are poorly understood. This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut-in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the lab data for predicting water imbibition volume during the shut-in period after hydraulic fracturing operations.

The combined application of multilateral horizontal drilling and multistage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a small fraction of the injected water during hydraulic fracturing treatments is recovered during flowback operations. The fate of nonrecovered water and its impact on hydrocarbon production are poorly understood. This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut‐in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River Basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the laboratory data for predicting water imbibition volume during the shut‐in period after hydraulic fracturing operations.

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.

Summary The importance of evaluating well productivity after hydraulic fracturing cannot be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage-fractured wells. Similarly, there have been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters, such as fracture pore volume (PV), half-length, and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture PV independent of fracture geometry. This study starts by use of rate-normalized-pressure (RNP) plots to observe changes in fluid-flow mechanisms from multistage-fractured wells. The fracture “pressure-supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between RNP and time, useful for interpreting flowback data in wells that show pseudosteady-state behavior (unit slope on log-log RNP plots). The linear relationship is implemented on a simple Monte Carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture PV by use of probabilistic distributions of average fracture compressibility and gas/water saturations. Also, the proposed model investigates the contributions of various drive mechanisms during flowback (fracture closure, gas expansion, and water depletion) by use of quantitative drive indices similar to those used in conventional reservoir engineering. Application of the proposed tank model to flowback data from 15 shale-gas and tight-oil wells estimates the effective fracture PV and initial average gas saturation in the active fracture network. The results show that fracture-PV estimation is most sensitive to fracture closure compared with gas expansion and water depletion, making fracture closure the primary drive mechanism during early-flowback periods. Also, the initial average gas saturation for all wells is less than 20%. The parameters estimated from the proposed model could be used as input guides for more-complex studies (such as discrete-fracture-network modeling and transient-flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.