Numerical simulation of productivity evaluation for multi-cluster fracturing in horizontal wells considering non-uniform proppant placement within fractures
Abstract
Non-uniform proppant placement during horizontal well hydraulic fracturing significantly impairs fracture conductivity and well productivity. Most existing models oversimplify conductivity distribution and lack integration between proppant transport and production prediction. This study presents a novel integrated numerical framework that fully couples fracture propagation, proppant transport, and post‑fracturing production. Unlike previous approaches that treat conductivity as uniform or decouple the physical processes, our model incorporates a dynamic conductivity evolution submodel that updates fracture conductivity in real time based on local closure stress and proppant concentration, enabling a more realistic representation of proppant placement effects. The model is validated against the commercial reservoir simulator ECLIPSE, with a cumulative production mismatch of less than 8% over 300 days, confirming its reliability. A two‑way coupled approach then systematically evaluates the impact of key pumping parameters: sand injection method, proppant size, injection rate, fluid viscosity, sand concentration, and perforation design. Results demonstrate that parameter sensitivity strongly depends on reservoir permeability. In ultra‑low permeability reservoirs (1 × 10⁻⁶ µm²), propped fracture area is the dominant productivity control, favoring constant‑concentration sand addition with finer proppant (70/140 mesh), lower injection rates, and lower viscosities to maximize…
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