To optimize hydrocarbon production from unconventional reservoirs, operators have been improving completion designs and well spacing for decades. Well spacing and completion design optimization is a challenging task due to the unknown hydraulic fracture geometry and the uncertainty of reservoir properties. Moreover, it is critical to understand the parent-child well effect and fracturing sequences to improve the entire field development plan. Combining fracture and reservoir diagnostic analysis with integrated geomechanics and reservoir simulation is an efficient and cost-effective approach to generate realistic fracture geometry, understand fluid flow behavior, and define fracture conductivity distribution. This paper presents a case study of integrated geo-mechanical and reservoir simulation with a developed fracture conductivity calculation workflow that was validated with diagnostic results to evaluate well spacing and completions design.
In the HFTS-2 development, two horizontal parent wells in the Wolfcamp (WFMP) formation were produced for more than two years before drilling adjacent child wells. Formation Micro-Imager (FMI) logs and Diagnostic Fracture Injection Tests (DFITs) were recorded in the adjacent child well, and they indicated that conductive hydraulic fractures were growing from the parent wells. The image log interpretation from the second-nearest neighboring child well indicates a few fractures could have extended from the parent wells to this image log well. Based on the distances and the hydraulic fracture density from the image logs, a 3D fracture model was calibrated for the parent wells.
The fracture geometry and simulated proppant concentration from the 3D fracture model were then exported to a reservoir simulator, where actual field production was history matched with constraints of measured far-field pressure data from the DFIT in each wellbore. (Details are presented in Part 2 of the study.) A rigorous fracture conductivity calculation workflow was developed and applied to reservoir simulation. This conductivity workflow uses simulated proppant concentration from the fracture model and conductivity measurements of fractures to define a conductivity distribution as an input to the reservoir simulator.
By applying the fracture conductivity calculation workflow and the measured far-field pressure constraints, the production history was matched for the full wellbores of two parent wells. Subsequent hydraulic fracture models of multiple child wells were developed, and the modeling results were validated by interpreting fracture dimensions from multiple diagnostic datasets, such as fiber optics, microseismic data, downhole pressure gauges, and DFITs. The calibrated and integrated fracture and reservoir models were used for investigating how completion designs and well spacing affect the full section production. (Details are presented in Part 2 of the study.)
This study:
1. Illustrates how modeled fracture geometry was calibrated using multiple diagnostic datasets recorded in both parent and child wells,
2. Describes a new fracture conductivity calculation algorithm utilizing modeled proppant concentration and experimental measurements of pressure-dependent and time-dependent fracture conductivity, and
3. Illustrates reservoir simulation where the history match of production is also constrained with far-field pressure measurements.
