A study recently published highlights significant advancements made in hydraulic fracturing technologies, which have revolutionized the productivity of shale oil reservoirs. Researchers have developed a dynamic geomechanical model (DG model) aimed at improving our comprehension of the hydraulic fracturing process and its impact on oil recovery. This model integrates unsteady seepage and dilation-recompaction approaches to simulate the multifaceted interactions within fracture networks and fluid dynamics.
Hydraulic fracturing has emerged as a game-changing technique, particularly for low-permeability shale reservoirs characterized by minimal initial productivity. The research's primary objective is to bridge gaps in our knowledge about fluid seepage mechanisms and fracture expansion patterns under actual field conditions. By applying field data to the numeric model, the researchers have created simulations closely mirroring real-world operations, allowing for enhanced predictions on productivity after hydraulic fracturing activities.
According to the authors, “The DG model can perform history matching on a multi-stage basis, enabling comprehensive and detailed analysis of the entire reservoir.” This capability addresses one of the key challenges in shale oil recovery—the need for rigorous studies on the interactions of fractures and fluids at various stages of production.
Historically, shale reservoirs have been seen as difficult to exploit due to their complex geological formations and properties—mainly, low porosity and low permeability—which lead to challenges of rapid production declines. The model significantly enhances the analytical framework by utilizing segmented data from field operations alongside production histories. The findings reveal how hydraulic fracturing induces the formations of complex fracture networks, increasing permeability and facilitating fluid movement within the reservoir.
A deep investigative effort was made to develop the hydraulic fracturing model using the DG framework. It emphasizes iterative calculations over discrete time steps, creating simulations aligned with the operational procedures of fractures and fluid injection. The model factors heavily on pressure-dependent changes to porosity and permeability within the reservoir and captures the physical interactions between injected fluids and rock formations accurately.
Researchers evaluated the performance of the model through extensive field data, particularly focusing on the multi-stage hydraulic fracturing undergone at the Chang 7 reservoir of the Changqing Oilfield, China. The multi-stage history matching employed revealed satisfactory alignment between simulated production dynamics and actual well outputs. The efficacy of the simulation was evidenced by the model's ability to delineate the fracture zone's geometries—as fluid is injected under high pressure, it induces dilation leading to increased porosity which facilitates enhanced production.
The authors state, “Hydraulic fracturing creates a fracture zone... and spreads outward radially.” The radial spread of fractures is pivotal for increasing oil and gas flow, showcasing the technology's necessity for optimizing resource recovery from shale formations.
The study emphasizes how the introduction of the DG model enhances dynamic property evolutions across multi-stage hydraulic fracturing processes—providing valuable insight for future initiatives aimed at increasing shale reservoir productivity. This research lays the groundwork for practitioners and policymakers to leverage hydraulic fracturing effectively, ensuring resources are utilized sustainably and efficiently.
Concluding, the DG model exhibits significant potential not just for historical analysis and validation but also for optimizing future designs and operational efficiency within hydraulic fracturing practices. Such advancements are expected to contribute meaningfully to tackling challenges associated with shale oil production.
