Large, high density fracture networks are necessary to deliver commercial production rates from sub-microdarcy permeability organic-rich shale reservoirs. Operators have increased lateral length and fracture stages as the primary means to improve well performance and, more recently, are tailoring completion techniques to local experience and reservoir-specific learning. In particular, closer fracture stage spacing or increased number of stages per well have driven improvements in well performance. Large scale adoption occurs when the change in performance is clearly linked to the reservoir-specific completion design.Horizontal well fracturing efficiency in unconventional reservoirs is notoriously poor. Numerous authors report that 40 to 60 per cent of frac stages or individual perforation clusters have been shown (albeit with highly uncertain surveillance methods) to contribute little or no production. The fracture initiation and propagation process is very complex in shale; it is affected by in-situ stress, geomechanical heterogeneity, presence of natural fractures, and completion parameters. Close cluster spacing can provide enhanced well production; however, if the spacing is too close, stress shadowing among these clusters can actually induce higher stresses, creating fracture competition.This paper presents an approach to the integration of these parameters through both state-of-the-art geological characterization and unconventional 3D hydraulic fracture modeling. We couple stochastic discrete fracture network (DFN) models of in-situ natural fractures with a state-of-the art 3D unconventional fracture simulator. The modeled fracture geometry and associated conductivity is exported into a dynamic reservoir flow model, for production performance prediction. Calibrated toolkits and workflows, underpinned by integrated surveillance including distributed temperature and acoustic fiber optic sensing (DTS/DAS), are used to optimize horizontal well completions. A case study is presented which demonstrates the technical merits and economic benefits of using this multidisciplinary approach to completion optimization.

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A geologically engineered shale completion optimization program was implemented for a liquid rich area of the Eagle Ford Play. This approach included detailed geological characterization, state-of-the-art unconventional 3D hydraulic fracture and reservoir flow modeling, as well as the latest available surveillance technology. This paper focuses on the integrated dataset used for optimizing unconventional completions.In the last decade, the United States has undergone an unconventional revolution fueled by the combination of horizontal drilling with hydraulic fracturing. Billions of dollars of capital investment are needed in unconventional resources and operators are competing to optimize developments and push for improved completion efficiency.With the pace of activity, ongoing learning curve, inherent uncertainty, and factory-mode mentality of operators, many shale well completions are sub-optimal with low fracture efficiency and a less than optimum reserves recovery.The push for completion and fracture optimization has prompted extensive learning projects to better understand the key drivers in fracture efficiency and the resulting production distribution along the horizontals. Recently, many innovative technologies have demonstrated significant promise to unlock greater potential within these wells. This paper will demonstrate a workflow for achieving completion optimization utilizing fiber optic DAS/DTS along with integrated modelling studies and complementary surveillance technologies such as tracers, production-logs, and micro-seismic. It will additionally provide examples of sub-optimized completions with low fracture efficiency, demonstrate the use of fiber optic DAS/DTS to improve overall completion efficiency, and outline the resulting production improvements achieved.

A geologically engineered shale completion optimization program was implemented for a liquid rich area of the Eagle Ford play. This approach included detailed geological characterization, state-of-the-art unconventional 3D hydraulic fracture and reservoir flow modeling, as well as the latest available surveillance technology. This paper focuses on the geological characterization of reservoirs which includes the generation of core-calibrated petrophysical and geomechanical rock properties as well as the natural fracture distribution.In the last decade, multistage completion in horizontal wells has successfully unlocked tremendous hydrocarbon resources in the onshore US. However, there are a large amount of wells which underperform due to oversimplified petrophysical and geomechanical property description, where reservoir heterogeneity is not properly represented. Low initial production rate is partially related to the poor uniformity among perforation clusters. Conventional subsurface reservoir description commonly involves the interpolation of core and log data acquired in pilot wells. The assumption of layer cake earth models from pilot wells can result in inaccurate reservoir property models for hydraulic fracture stimulation.Optimizing completion design requires acquiring and interpreting petrophysical and geomechanical properties along the horizontal well. Petrophysical properties include total organic content, porosity, permeability, gas-filled porosity and clay volume. Geomechanical parameters include minimum horizontal stress, Young's Modulus and Poisson's ratio. Alternative isotropic and anisotropic stress profiles of reservoirs and encasing rocks are used to simulate hydraulic fracture initiation and propagation as well as expected well performance. In addition to the later static properties, the density and orientation of natural fractures from borehole image and acoustic logs enhance the optimization workflow. This paper provides specific examples on how natural fractures and geological properties affect completion efficiency and production.Cutting-edge surveillance monitoring tools (i.e. fiber optics) confirmed an improvement of perforation cluster uniformity. The in-depth petrophysical and geomechanical reservoir description coupled with the optimized completion design yielded a 30% increase of the initial production rate in a well compared to an offset well having a simple geometrical completion design.