Flowback Fracture Closure: A Key Factor for Estimating Effective Pore Volume

Abstract

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.

Upscaling Water Flow in Composite Nanoporous Shale Matrix Using Lattice Boltzmann Method

“…In this work, we investigate water flow in shale matrix given that multistage hydraulic fracturing operation is currently the most feasible and effective way to produce shale gas and that fracturing fluid is mostly composed of water. In addition, previous research shows injected water not only remains stored in the fracture system but also infiltrates the nanoscale pores of shale matrix (Ezulike et al, 2016). In another aspect, the topic of single-phase water flow in nanoscale channels inspires scientific debate, and researchers propose the enhancement factor in some superhydrophobic materials may reach up to several orders (Lei et al, 2016).…”

Stochastic Modeling and Assisted History-Matching Using Multiple Techniques of Multi-Phase Flowback from Multi-Fractured Horizontal Tight Oil Wells

“…In previous work, [16] [17] applied MC simulation to the same data set, although less iterations were conducted with significantly more input parameters and with wider bounds, bringing the results into question. The GAPS algorithm has also been tested by [4] for history-matching three-phase flowback with a numerical simulator and [3] attempted to use a combination of algorithms to try to decouple parameters in one of their analysis tools, although more rigorous methods could have been applied.…”

Semianalytical method of two‐phase liquid transport in shale reservoirs and its application in fracture characterization

“…During flowback period, the bottomhole pressure is above the initial pressure of the intact reservoir before hydraulic fracturing, which is 8000 psi, indicating the supercharge effect in the fractures during well stimulation. 9 While, the bottomhole pressure stays below 8000 psi during long-term production. Accordingly, the initial pressure of fracture and matrix systems are both set to be 9600 psi for flowback to account for the supercharge effect and stabilized condition during shut-in.…”

“…To consider multiphase flow during flowback, Dehghanpour's group 9 proposed a two-phase tank model to estimate the fracture pore volume and fracture closure by defining total effective compressibility. Later, they applied the single-phase tank model developed to extract the fracture pore volume from the tight oil wells and proposed a workflow to determine the fracture compressibility using Diagnostic Fracture Injection Test data.…”