| dc.description.abstract | In hydraulic fracturing, the proppant-filled fracture length at the end of pumping strongly influences the fluid conductivity of natural oil and gas. Therefore, it is very important to regulate proppant bank height and suspended proppant concentration across the fracture to increase the recovery of shale hydrocarbon. From a control engineering viewpoint, hydraulic fracturing has been traditionally viewed as an open-loop problem. Well logs and mini-frac test results are interpreted prior to operation in order to obtain petrophysical and rock-mechanical properties of the formation. The operation is designed based on the properties and then is conducted accordingly. However, the open-loop operation may lead to poor performance if there are large disturbances and plant-model mismatch.
In this research, a model predictive control framework is developed for the design of pumping schedules to regulate the spatial variation of proppant concentration across the fracture at the end of pumping for both of conventional and unconventional reservoirs. To this end, we initially focus on the development of a first-principle model of hydraulic fracturing process to obtain fundamental understanding of the proppant bank formation mechanism and its relationship to manipulated input variables such as proppant concentration and flow rate of the injected fracturing fluids by considering a single fracture. Then, a model-based feedback controller is developed to achieve the uniform proppant bank height and suspended proppant concentration along the fracture at the end of pumping for both of conventional and unconventional reservoirs by explicitly taking into account the desired fracture geometry, type of the fracturing fluid injected, total amount of injected proppant, actuator limitations, and safety considerations.
Then, we extend this study to multi-stage hydraulic fracturing, where in each stage, multiple simultaneously propagating fractures are generated. In multi-stage hydraulic fracturing treatments, simultaneously propagating multiple fractures with close spacing often induce non-uniform fracture development due to “stress shadow effects”. In order to mitigate these undesired stress-shadow effects, we propose a model-based design technique by utilizing the limited entry design technique to compute the flow rate of fracturing fluids and the perforation conditions which will promote equal distribution of fracturing fluids to achieve uniform growth of multiple fractures. Then, a model-based feedback controller is developed to achieve a uniform proppant bank height in simultaneously propagating multiple fractures at the end of pumping by handling the undesired stress-shadow effects using the optimal perforation conditions.
In hydraulic fracturing, higher fracturing fluid injection rates can trigger increased stress, thereby creating more microseismic events; particularly, simultaneously occurring multiple microseismic events can reduce measurement errors. This suggests a new state and output estimation scheme that utilizes the dependence between the fracturing fluid injection rate (i.e., manipulated input) and measurement errors. Motivated by this, we improve our control framework for measurement uncertainty reduction while achieving the original control task of proppant bank height control in hydraulic fracturing. Specifically, the developed model-based feedback control system regulates the uniformity of proppant bank height along the fracture length and achieve accurate state and output estimation by manipulating the fracturing fluid pumping schedule that includes the fracturing fluid injection rate and proppant concentration at the wellbore.
In some of the unconventional reservoirs, natural fractures (discontinuities in shale rock formations) are commonly observed using advanced fracture diagnostic techniques such as microseismic monitoring, core samples and outcrops. In naturally fractured unconventional reservoirs, naturally present fractures will interact with hydraulic fractures and divert fracture propagation. Because of complex fracture growth, the ultimate goal of hydraulic fracturing operation in naturally fractured unconventional reservoirs should be changed from achieving a desired fracture geometry to maximizing the total fracture surface area (TFSA) for given fracturing resources, as it will allow more drainage area available for oil recovery. To further consider the interaction between hydraulic fractures and natural fractures, we develop a model-based pumping schedule that maximizes the TFSA by utilizing a recently developed unconventional complex fracture propagation model called Mangrove describing complex fracture networks in naturally fractured unconventional reservoirs. | en |
