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Abstract In this study, we propose a new method for estimating average fracture compressibility during flowback process, and apply it on flowback data from thirty multi-fractured horizontal wells completed in Eagle Ford, Horn River, Montney and Woodford formations. We conduct complementary diagnostic flow regime analyses and calculate by combining a flowing material balance equation with rate-decline analysis. We observe two production signatures during flowback: (1) single-phase water production followed by hydrocarbon breakthrough and (2) immediate production of hydrocarbon with water. Water rate-normalized-pressure plots show pronounced unit slopes, suggesting pseudo-steady state flow. Water decline curves follow a harmonic trend during multiphase flow; from which we forecasted ultimate water production as an estimate of initial fracture volume. The estimates are within the range of 7 – 200 × 10 psi, and are generally lower than the values previously estimated using Aguilera’s type curves and DFIT data. Also, estimates for deeper dry gas wells are relatively higher than those for shallower oil wells.
Summary Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.
Abstract We analyzed flowback (FB) and post-flowback (PFB) production data from six multi-fractured horizontal wells completed in Eagle Ford Formation. The wells are supercharged at the beginning of the flowback process and the reservoir pressure remains above bubble point during the post-flowback period. Interestingly, we observe a pronounced unit slope (pseudo-steady state) in the rate-normalized pressure (RNP) plots of water for post-flowback period, while such unit slope is not observed for the flowback period. We developed a conceptual and mathematical model to describe these observations and to estimate the average fracture pore volume (Vf) during the post-flowback process. This model assumes no water influx from matrix into the fracture system, which is consistent with the lack of mobile water in the target reservoir. It also assumes stable influx of oil from matrix into the fracture system with insignificant mass accumulation of oil in the fracture system. Therefore, water production at pseudo-steady state conditions occurs under the driving forces of water expansion, oil expansion, and fracture closure. We also performed decline curve analysis on water production data to estimate initial Vf, as the fractures tend to be fully saturated with water at the beginning of the flowback process. The difference between ultimate water recovery and average Vf from the PFB model represents the loss in fracture volume due to fracture closure. The results show that about 65% of fracture closure occurs after 7 months of PFB production. Fracture closure is the dominant drive mechanism during FB and early PFB periods when reservoir pressure drops rapidly. Introduction Analysis of flowback is becoming a common practice for early characterization of fractured horizontal wells completed in unconventional reservoirs. Several authors have developed different models for analyzing early flowback data to characterize complex fracture networks created by multi-fractured horizontal wells. Examples of recent studies include Abbasi et al. (2012, 2014), Ezulike et al. (2013), Clarkson and Williams-Kovacs (2013), Ezulike and Dehghanpour (2014a, b), Jia et al. (2015), Xu et al. (2016), Ezulike et al. (2016), Yang et al. (2016), Williams-Kovacs (2017) and Chen et al. (2017).
Summary In this study we estimated the initial effective fracture pore volume (Vfi) and fracture volume loss (dVef) for 21 wells completed in the Montney and Eagle Ford formations. We also evaluated the relationship between dVef and choke size. First, we applied rate‐decline analysis to water‐flowback data of candidate wells to estimate the ultimate water recovery volume, approximated as Vfi. Second, we estimated dVef using a fracture compressibility relationship to evaluate the fracture volume loss of the Eagle Ford wells. Third, we investigated the effect of choke size on dVef for the Eagle Ford fastback and slowback wells. Semilog plots of flowback water rate vs. cumulative water volume show straight‐line trends, representing a harmonic decline. The estimated Vfi accounts for approximately 84 and 26% of the total injected water volume (TIV) of the Montney and Eagle Ford wells, respectively. The results show that approximately 10% of the fracture volume is lost during flowback. This loss in fracture volume predominantly happens during the early flowback and becomes minimal during the late flowback period. The results show a relatively higher dVef for fastback (a flowback process with a relatively large choke size) wells compared with that for slowback (a flowback process with a relatively small choke size) wells. In this study we proposed a method to estimate the initial fracture volume and investigated the loss in fracture volume during the flowback process. Analyses of the field data led to an improved understanding of the factors that control water flowback and the effective fracture volume.
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.