With the huge growth in the stimulation of naturally fractured formations, it is clear that the industry needs new hydraulic fracturing simulation tools beyond the limits imposed by pseudo3D fracturing model. Discrete element models (DEM), in which both matrix block behavior and fracture behavior are explicitly modeled, offer one option for the specific modeling of hydraulic fracture creation and growth in naturally fractured formation without, for example, the assumption of bi-planar fracture growth.In this paper, we show the results of the successful realistic simulations of fluid injection into a given NFR using the 3DEC DEM model. The simulations included coupled fluid flow-deformation analysis, failure type and extent calculations, as well as a series of parametric analyses. The parameters investigated included: 1) injection rate and its effect on the overall injection results, and 2) fluid viscosity, which had a significant influence on the ratio of tensile (mode 1) failure versus shear failure.
Recent developments in both SRM and EMA technologies are described using case studies of the techniques applied to hydrofracture stimulations. We identify and discuss some future developmental challenges these technologies face, including their further integration and validation so as to provide more efficient and robust application of the FNE approach.
It has progressively become more accepted that fracture growth, particularly in extremely low permeability, naturally fractured reservoirs cannot be reliably represented by conventional planar simulations. Characterizing evolution of multiple, non-planar, interconnected, and possibly non-vertical hydraulic fractures requires hydraulic and mechanical characterization of the nominally intact matrix as well as existing latent or healed fracture networks. This paper describes an approach to representing and assessing complex fracture growth and associated production prediction through this generated fracture. There are three stages in this protocol. The first is a representation of the fracture networks. The second is importing this DFN (discrete fracture network) into a coupled geomechanical simulator and representation of fracture evolution. The final step is importing the resultant conductive system into a multiphase DFN reservoir simulator for the prediction of production rates and the generation of pressure and saturation maps.The complex fracture network evolution during stimulation is represented using a Discrete Element Method, DEM -starting from the representation of a naturally fractured reservoir and modeling complex, non-planar, hydraulic fracture propagation. A representative fracture network was used under a variety of conditions. The objectives of this modeling include: 1) assessing the effects that operational parameters (such as injection rate) have on the volumetric extent of the fracture system or domain and the extent of fluid penetration in the natural fractures; and 2) assessing the degree of water blocking and loss of conductivity in the fracture system using a DFN reservoir simulation model. Both these issues are crucial for treatments in shale gas systems. SPE 127888 IntroductionWe often hear people saying that their reservoir has no fractures. This simply is not true -all material is flawed and fractures exist at different scales. Furthermore, in many tight reservoirs, healed fractures can be re-activated, in tension or shear. Consequently, a fracture model of the reservoir is needed.
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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