The combination of matrix acidizing experiments with visualization techniques is commonly used to elucidate the details of wormhole networks formed during matrix acidizing of carbonate reservoir rock. Previous experimental studies of wormhole growth have focused mainly on small linear core plugs, with only a limited number of radial flow studies published in the literature. Results from these conventional experiments have provided extensive information on linear wormhole growth in one dimension (1-D) along with some basic insights into radial growth mechanisms in 2-D. However, larger-scale test systems must be considered if 3-D wormhole characteristics are to be understood. Toward that end, a new methodology has been developed which integrates (1) acidizing experiments on carbonate rock samples up to 14 ft3 in volume, (2) high-resolution nondestructive imaging and analysis, and (3) computational modeling to extend the results of experiments to field applications. This article highlights the experimental and imaging components of the methodology.

Fracture nucleation and propagation are controlled by in-situ stresses, fracture treatment design, presence of existing fractures (natural or induced), and geological history. In addition, production-driven depletion and offset completions may alter stresses and hence the nature of fracture growth. For unconventional oil and gas assets the complexity resulting from the interplay of fracture characteristics, pressure depletion, and stress distribution on well performance remains one of the foremost hurdles in their optimal development, impacting infill well and refracturing programs. ExxonMobil has undertaken a multi-disciplinary approach that integrates fracture characteristics, reservoir production, and stress field evolution to design and optimize the development of unconventional assets. In this approach, fracture modeling and advanced rate transient techniques are employed to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite element geomechanical modeling (coupling stresses and fluid flow) to predict fracture orientation in nearby wells. In this paper, an integrated methodology is described and applied to a shale gas pad as a case study. The work reveals a strong connection between reservoir depletion and the spatial and temporal distribution of stresses. These models predict that principal stresses are influenced far beyond the drainage area of a horizontal well and hence can play a critical role in fracture orientation and performance of neighboring wells. Strategies for manipulating stresses were evaluated to control fracture propagation by injecting, shutting-in, and producing offset wells. In addition, we present diagnostic data obtained from the pad that demonstrates inter-well connectivity and hydraulic communication within the pad. The workflow presented herein can be used to develop strategies for (1) optimal infill design, (2) controlling propagation of fractures in new neighboring wells, and (3) refracturing of existing wells.