Fracture Propagation, Leakoff and Flowback Modeling for Tight Oil Wells Using the Dynamic Drainage Area Concept

Abstract

Recently it has been demonstrated that flowback data obtained immediately after fracture stimulation of multi-fractured horizontal wells (MFHWs) completed in tight/shale reservoirs may be analyzed quantitatively for hydraulic fracture properties. However, the initial conditions of fluid pressures and saturations at the start of flowback, which are a critical starting point for flowback simulation, are generally unknown and must be approximated. In order to properly initialize flowback simulations, the pre-flowback fracture stimulation treatment, as well as post-treatment shut-in period, should first be modeled in order to provide a reasonable estimate of fluid pressures and saturations within the hydraulic fracture and adjacent reservoir. In recent work, the authors developed a semi-analytical model to history-match flowback and early-time production data of MFHWs completed in tight oil reservoirs using the "dynamic drainage area" (DDA) concept. The model assumes that each fracture stage consists of a primary hydraulic fracture (PHF) region, and an adjacent enhanced fracture region (EFR) or non-stimulated region (NSR) in the reservoir. However, initial fracture fluid pressure in the PHF, and fluid pressure/saturation distributions in the adjacent EFR/NSR are required for the model initialization and are highly uncertain. In the current work, flowback data from a previously-analyzed MFHW horizontal well completed in a tight oil reservoir is revisited to determine if flowback initial conditions could be constrained rigorously. For this purpose, frac modeling (net-pressure analysis) was first performed using fracture treatment data for the well and commercial and publically-available simulators to constrain PHF property input for the DDA flowback model. The DDA model, run in injection mode, was then used to calculate the frac fluid leakoff rate from the PHF to the NSR during the fracture treatment, using the field frac pressures as input. Importantly, leakoff is modeled more rigorously using the DDA model than for the frac simulator, because it accounts for two-phase flow and stress-dependent permeability. Leakoff after the fracture treatment and before the flowback period was also modeled using the DDA approach to estimate the pre-flowback NSR fluid saturations and pressures, which served as the initial conditions for flowback modeling. The amount of leakoff estimated with the model is relatively small in this case, in part due to the small volumes of fluid used in the fracture treatment and low permeability of the reservoir. The resulting flowback history-match (also performed using the DDA model, in flowback mode) is similar to that achieved previously because the pre-flowback leakoff modeling resulted in only a slightly elevated water saturation estimate over virgin reservoir conditions. The results of this innovative approach to flowback modeling should be of interest to those petroleum engineers interested in quantitative analysis of flowback data to obtain fracture properties, but who are concerned about correct initialization of models for flowback simulation leading to more realistic results.

A semi‐analytical model for capturing dynamic behavior of hydraulic fractures during flowback period in tight oil reservoir

“…During the flowback, formation fluid flows from the matrix into the fracture and then along the fracture into the wellbore. The matrix single-phase (oil) flow is simulated by the analytical transient linear flow equation and (9) dynamically coupled with the fully numerical fracture multiphase (oil + water) flow equation by imposing continuity of pressure and flux on the surfaces of the fractures. At the same time, a nonlinear formula is used to describe the relationship between fracture aperture and the stress acting on the surfaces of the fracture, and the fracture aperture calculated by the displacement discontinuity method (DDM) is used to characterize fracture pore volume and fracture conductivity, which is dynamically updated in flow equations, at every time step.…”

“…Flowback data obtained from a multifractured horizontal well completed in a tight oil reservoir are analyzed by the new coupled model. This field case was previously analyzed by Clarkson and Williams-Kovacs, Clarkson, Zhang and Clarkson and Jia et al 4,[7][8][9]38 However, only static parameters such as fracture permeability were obtained by analyzing the flowback data. Therefore, the object to revisit this example is to capture reliable fracture dynamic parameters by historical matching the field data.…”

“…As Figure 1B illustrates, each fracturing stage is idealized as two regions: a primary hydraulic fracture (PHF) and an adjacent reservoir region with enhanced permeability due to nature fractures reactivation. 9,19 The PHF is assumed to be initially filled with treatment water and majority of proppants. Although treatment water will leak off to the formation during stimulation, it is difficult to quantify the distribution of water in the matrix.…”

Semi-Analytical Model for Two-Phase Flowback in Complex Fracture Networks in Shale Oil Reservoirs

“…To accommodate the reactivation of pre-existing natural fractures, they defined an enhanced fracture region (EFR) along the primary fracture, inside which the permeability is enhanced. However, this approach indicates that overall permeability is enhanced in the direction perpendicular to the primary fracture, which misleads the true directionality of fracture permeability in complex fracture networks [8]. A complex fracture network is desirable from the design perspective as it increases the effective surface area of the wellbore and enable more-efficient linear flow to predominate over the radial flow.…”

“…Production from reservoirs with complex fracture networks is often modeled by a numerical simulator, which can be computationally expensive for use in inverse analyses, unless some meshless methods are utilized for flow through fractures [9]. Most available flowback models incorporate fracture closure by using constant fracture compressibility for wells with bi-wing planar fractures [4,5,8,10]. However, the outcome can be misleading for two main reasons: (1) compressibility of propped fracture is expected to evolve with effective pressure based on the analytical solution for compliance of proppant beds.…”