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Early fluid production and flowing pressure data gathered immediately after fracture stimulation of multifractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale-gas (and other hydraulically fractured) reservoirs. These early data, which often consist of hourly (if not more frequent) monitoring of fracture/formation fluid rates, volumes, and flowing pressures, are gathered on nearly every well that is completed. Additionally, fluid compositions may be monitored to determine the extent of load fluid recovery, and chemical tracers added during stage treatments to evaluate inflow from each of the stages. There is currently debate within the industry of the usefulness of these data for determining the long-term production performance of the wells. "Rules of thumb" derived from the percentage of load-fluid recovery are often used by the industry to provide a directional indication of well performance. More-quantitative analysis of the data is rarely performed; it is likely that the multiphase-flow nature of flowback and the possibility of early data being dominated by wellbore-storage effects have deterred many analysts.In this work, the use of short-term flowback data for quantitative analysis of induced-hydraulic-fracture properties is critically evaluated. For the first time, a method for analyzing water and gas production and flowing pressures associated with the flowback of shale-gas wells, to obtain hydraulic-fracture properties, is presented. Previous attempts have focused on single-phase analysis. Examples from the Marcellus shale are analyzed. The short (less than 48 hours) flowback periods were followed by long-term pressure buildups (approximately 1 month). Gas þ water production data were analyzed with analytical simulation and rate-transient analysis methods designed for analyzing multiphase coalbedmethane (CBM) data. This analogy is used because two-phase flowback is assumed to be similar to simultaneous flow of gas and water during long-term production through the fracture system of coal. One interpretation is that the early flowback data correspond to wellbore þ fracture volume depletion (storage). It is assumed that fracture-storage volume is much greater than wellbore storage. This flow regime appears consistent with what is interpreted from the long-term pressure-buildup data, and from the rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a region around perforation clusters in each stage, one can see that fluid-production data can be analyzed with a two-phase tankmodel simulator to determine fracture permeability and drainage area, the latter being interpreted to obtain an effective (producing) fracture half-length given geometrical considerations. Total fracture half-length, derived from rate-transient analysis of online (post-cleanup) data, verifies the flowback estimates. An analytical forecasting tool that accounts for multiple sequences of post-storage linear flow, f...

Summary The application of rate-transient-analysis (RTA) concepts to flowback data gathered from multifractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic-fracture volume/conductivity. However, the initial fluid pressures and saturation in the fracture network and adjacent reservoir matrix are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. In this study, we present a semianalytical flow model, coupled with a hydraulic-fracture (fracture) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback. In previous work, a semianalytical model based on the dynamic-drainage-area (DDA) concept was used to simulate water-based fluid leakoff from an MFHW into a tight oil reservoir (Montney Formation, western Canada), with minimal mobile water, during and after fracturing operations. The model assumed that each fracturing stage can be represented by a primary hydraulic fracture (PHF) containing the majority of the proppant, and an adjacent nonstimulated reservoir (NSR) or enhanced fracture region (EFR), which is an area of elevated permeability in the reservoir caused by the stimulation treatment. Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through using a simple analytical fracture model. Although this approach was considered novel, several improvements and additional laboratory constraints were considered necessary to yield more accurate predictions of initial flowback conditions. In the current work, the modeling approach described previously was improved by representing the EFR with a dual-porosity system; fully coupling the fracture model (used for PHF creation and propagation) with the DDA model for fluid-leakoff simulation into the EFR and adding a proppant-transport model; and modeling the shut-in period. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously gathered laboratory data was used. Laboratory-derived propped (PHF) and unpropped (EFR) fracture-permeability/conductivity data as a function of pore pressure, as well as fracture-compressibility data, were used as constraints for the model. It should be noted that our model assumes that fracture closure has no effect on the pressure/saturation of the PHF/EFR/matrix. The improved model was reapplied to the tight oil field case and yielded more realistic estimates of initial flowback conditions, enabling more confident history matching of flowback data. The results of this study will be important to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring proper model creation.

Unconventional light oil reservoirs are currently a primary focus of exploration and development activity in North America. Operators are seeking new methods to characterize hydraulic fractures generated during stimulation of multi-fractured horizontal wells completed in these reservoirs, particularly early in the well life. One such method is to quantitatively analyze flowback fluids immediately after fracturing operations. In previous studies it has been shown that flowback fluid rates and pressures can be modeled to obtain hydraulic fracture half-length and conductivity. In this work, we develop an analytical procedure and methods for analyzing pre- and post-breakthrough of hydrocarbons during flowback of light tight oil wells. Flowback of multi-fractured horizontal wells, stimulated with water-based fluids in tight oil reservoirs, often consists of a short period of single-phase (water) flow followed by breakthrough of hydrocarbons, after which multi-phase flow (oil, water and gas) occurs. Our modeling approach therefore accounts for these multiple stages of flowback fluid production. The first flowback regime typically observed is fracture storage/depletion – this stage is analyzed by modeling single-phase depletion of the fracture pore volume from which a pre-hydrocarbon breakthrough estimate of fracture permeability and half-length is obtained. A stress-dependent permeability can be included to account for fracture closure and consequent conductivity loss during flowback. Fracture storage is followed by formation fluid breakthrough, which causes a deviation from the depletion signature. This stage is modeled by assuming transient linear flow of oil and formation water to the fracture, and accounting for consequent multi-phase flow in the fracture. The primary properties adjusted to match pre- and post-hydrocarbon breakthrough fluid production include fracture half-length and permeability, fracture relative permeability, breakthrough pressure and reservoir permeability. We have observed, as have others, that effective fracture half-length may be significantly reduced following hydrocarbon breakthrough. Our new method for tight oil reservoir flowback analysis is tested against a field example. As with previous studies associated with shale gas, significant uncertainty in fracture property estimation results from the analysis, which we will address in future work.

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