This talk addresses some recent advances in answering four key questions that arise when pad drilling and completing wells in unconventional plays:
- What is the optimum fracture / cluster spacing and sequencing?
- What is the optimum well spacing?
- What is the optimum wellbore trajectory for maximizing IPs and long term production (including artificial lift)?
- Where is the frac water going, what is its impact on well productivity and EUR?
The creation of a hydraulic fracture and production or injection of fluids into the producing formation changes the stress distribution in the rock. This stress shadow can influence the growth of subsequent fractures and have a significant influence on well IP and EUR. By analyzing the net pressure, radioactive tracer, fluid returns and microseismic data from pad drilled wells, we show that stress interference between fractures and between wells occurs routinely and leads to fracture reorientation. We propose that the stress shadow created by the propped fracture and the associated induced unpropped (IU) fracture network decreases over time. The hydraulic fracture and the induced unpropped fractures close as a result of fluid leak-off resulting in a reduction in the spatial extent of the stress shadow. This makes subsequent fracture stages less susceptible to fracture interference and more efficient (by avoiding the wastage of fluid / proppant into pre-existing fractures networks). This suggests that increasing the time between successive fractures in a wellbore will lead to improved fracture performance. This provides, for the first time, a reasonable explanation of why zipper fracs work better than conventional fracs. However, our work suggests that there may be other fracture sequencing strategies for accomplishing this even more effectively.
A general geo-mechanical modeling framework (UT-Multifrac) has been used to analyze and integrate field pressure, rate, microseismic, tracer and production data. It is shown that pressure data obtained during fracturing can be used as a diagnostic tool to study fracture interference. After the model has been calibrated and validated with field data, it can be used to perform pad-scale simulations to determine optimum fracture spacing and well spacing while properly accounting for both mechanical and poroelastic stress interference effects. Simulations can be run to analyze the impact of important formation properties and fracture design parameters. These simulations can be used for making operational decisions for drilling (well spacing, infill drilling), production (avoiding frac hits) and completion (frac spacing, sand volumes, fluids, sequencing) for a particular reservoir environment.
Fluid selection and flowback control are shown to influence the performance of pad fraced wells. Our ability to efficiently flow back both frac water and reservoir liquids is key to good well performance. Simulations and field performance data are used to show how this flowback is controlled by fluid selection, flowback choke control and wellbore trajectory. Simulations are run using UT-Pipeflow and a reservoir simulator and compared with PLT results to select the appropriate wellbore trajectory and predict the clean-up and performance of wells completed toe-up and toe-down for different fluid environments.