Fracture Height and Barrier Identification in a Conventional Formation: Introducing a Fracture Barrier Index and its Implications to Fracture Simulation and Well Productivity

Abstract The AMN Formation is a sandstone reservoir and the primary target in the FKR field development in Sultanate of Oman. Over 12 wells have been drilled in recent years, accompanied by numerous studies aimed at understanding its production potential and fracability. The processes governing hydraulic fracture geometries in the AMN Formation are continuously being assessed, particularly due to the complexity introduced by fine-scale dispersion of formation properties and their vertical variability. Fracture height is a critical parameter for several decisions, including the depth of penetration into the formation, the number of stages (which serve as inputs to production models), and calibration of fracture simulations. Its significance is further emphasized in reservoirs characterized by multiple fluid phases: free gas, trapped gas, and water zones. In this paper, we examine the intrinsic fine-scale features from open-hole data that influence fracture height growth, with a particular emphasis on moving beyond the common assumption of a homogeneous reservoir. Additionally, we explore the broader implications of transitioning from a homogeneous to an anisotropic reservoir model for fracture simulation and, ultimately, well productivity. We focus on the following factors: sandstone density, principal stress, geomechanical properties, and laminations with lithological contrasts. The AMN Formation is heterogeneous and anisotropic under a normal stress regime. This anisotropy was derived from correlating open-hole features with actual fracture data from previous wells. The resulting 1D anisotropic geomechanical model significantly impacts fracture height and, consequently, well production performance. This conclusion is supported by actual fracture job data. As observed, the computation of 1D geomechanical models using both low- and high-resolution inputs affects fracture height simulation. In this paper, we present an example to highlight these differences and the consequences of the averaging process used during stage selection in fracture simulation, which in turn influences the resulting fracture height growth. While the presence of fine-scale reservoir features in the AMN Formation has been previously documented, their impact on fracture height has not been thoroughly examined. This study extends the investigation across the field to enhance well productivity by effectively managing fracture height to cover the entire pay zone. The inherent challenges in detecting, characterizing, and accurately modeling these fine-scale features—and simulating their interaction with hydraulic fractures—are addressed through a developed workflow. This workflow is designed to characterize these features and incorporate them as inputs for fracture simulation. Additionally, we discuss the field data that contribute to understanding and calibrating fracture height and production allocation. The paper concludes with a summary of the effects, their influence on fracture height, and their implications for fracture simulation and well productivity.