## Abstract

This paper presents a new integrated workflow that couples geology, geomechanics and geophysics (3G) with a constrained asymmetric frac model as applied to a Wolfcamp well to address the concerns of well interference. The proposed workflow enables the ability to adapt the frac design of each stage based on the in-situ geologic and geomechanical variability. The objective of this approach is to identify the variable treatment parameters required to overcome the stress heterogeneity and estimate the impact of the adaptive frac design on the final fracture geometry.

The lateral stress gradients resulting from the pressure depletion due to a nearby producing well and the fluid leak-off due to opening of natural fractures are fine-tuned to account for asymmetry observed in the geomechanical modeling. The role of the natural fractures is emphasized and practical approaches to estimate a validated natural fracture model are described and illustrated. A validation well is used to highlight the importance of the input natural fracture model in calculating validated differential stress and strain that reproduce the main features of the microseismic. With this validated strain model, a constrained frac design provides the proper asymmetric fracture geometry able to pinpoint the poor and good frac stages. Once the workflow is extensively validated, it can be used on target wells to avoid frac hits.

In this Wolfcamp example, the challenge was to find the optimal frac design to minimize interference of an infill well with existing offset producers. To address the possible zones of interference, the stage spacing was locally increased to 152 m (500 ft), and the treatment was especially modified in the middle stages of the well. This resulted in reducing the number of stages from 40 to 34, specifically in zones indicating high probability of interference. The design was altered from pumping a mixture of 320,000 lb of 100 mesh and 40/70 mesh sand to 220,000 lb of 40/70 mesh sand, and the injected fluid viscosity was increased from 10 centipoise (cP) for slick water to 30 cP for linear gel as better carrying capacity was required to pump only 40/70 mesh sand. Additonally, the injection rate was reduced from 105 bbl/min to 80 bbl/min.

The integrated approach allows for the ability to adapt the frac design to in-situ conditions including heterogeneity in the stress fields and the pressure depletion from existing producers. Adaptive frac design significantly reduces the probability of frac hits and well interference. The proposed modeling workflow enables greater investment efficiency and overall field development optimization.