Enhancing total fracture surface area in naturally fractured unconventional reservoirs via model predictive control

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 the 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. Unfortunately, there are no such techniques available to develop pumping schedules to maximize TFSA for given fracturing resources in naturally fractured unconventional reservoirs. Motivated by this, in this work, we will develop a new model-based pumping schedule by utilizing a recently developed unconventional complex fracture propagation model called Mangrove as our virtual experiment describing complex fracture networks by accounting for the interaction between hydraulic fractures and natural fractures. Initially, using the simulation data from Mangrove, a reduced-order model (ROM) is constructed, which is then used to develop a Kalman filter utilizing the available measurement to estimate the unmeasurable ROM states. Then, we propose a model-based feedback control system to determine the fracturing fluid pumping schedule that maximizes TFSA, which will lead to an enhanced oil production rate from naturally fractured unconventional reservoirs. We demonstrate that by using the proposed control scheme, TFSA can be greatly enhanced which will lead to an oil production rate greater than those of existing pumping schedules which were developed without considering natural fractures.