The existing transient models for multistage fractured horizontal wells assume single-phase flow. This assumption is violated in early times, when hydraulic fractures are filled with both water and gas/oil. Hence, the need for a model that can capture the transient 2-phase (water + gas/oil) flow in fractures during flowback. This paper proposes a flowback analysis model (FAM) which accounts for transient 2-phase flow in hydraulic fractures by extending the existing linear dual-porosity model (DPM).
FAM expresses hydrocarbon relative-permeability as a non-linear function of time to account for rapid watersaturation drop in the HF network. This function is obtained by combining the cumulative water + gas/oil data measured during flowback operations with drainage relative-permeability curves from existing literature. The resulting relative-permeability function of time is then incorporated into the existing DPM static-framework toobtain FAM flow equations. The FAM equations capture the fluid physics from flowback until hydrocarbon production in the life of a multifractured well. They are solved with Laplace transforms. Type-curves are then generated by numerically inverting the resulting Laplace space solutions to time-space using the Gaver-Stefhest algorithm. FAM converges to DPM at the limit of single-phase flow.
This paper develops an integrated workflow for analyzing transient 2-phase flowback data. It applies the workflow to history-match flowback data from a multifractured shale-gas well completed in the Horn River Basin. This match
estimates effective half-length, pore-volume of active secondary fractures interconnected with HF, percentage of injected fluid left in the HF, and
forecasts gas production.
Results from this study show how short-period flowback data analysis (FDA) can provide quick estimates of reservoir parameters (before full production data becomes available) and forecast long-term gas recovery. Also, the outputs from FDA could be used as inputs during post-flowback production data analysis to
reduce uncertainty in reservoir parameter estimates and
improve fracture characterization.
This study encourages the industry to start careful measurement of rate and pressure immediately after putting wells on flowback.
