Natural fractures are a crucial factor in determining fracture and well spacing in horizontal wells. Their attributes affect the created fracture network and thereby the well producivity and EUR. However, information about the properties of natural fractures is seldom available. In this study, we used a detailed core description from the Hydraulic Fracture Test Site (HFTS), funded by the DOE and an industry consortium, to obtain in-situ natural fracture distribution data. The data was used as input into a hydraulic fracturing simulator to model fracture growth in the presence of natural fractures. The results obtained were then compared with field observations of cores taken from a slant infill well drilled into the hydraulically fractured rock. The core taken from the slant well located adjacent to the hydraulically fractured well is used to characterize the natural fractures (density and orientation). A two-dimensional discrete fracture network (DFN) is generated based on the core description. Nine coring operations are simulated on the created DFN to generate synthetic core descriptions. Attributes (length and density) of natural fractures are calibrated to match the results obtained from simulated coring operations with real core data. Multi-stage hydraulic fracturing simulations are performed using the calibrated DFN, and the results are presented in this paper. The core analysis identified three different types of fractures: hydraulic fractures, intact natural fractures, and natural fractures activated by hydraulic fractures. The density and orientations obtained from the core description provide valuable insights on the complex fracture growth behavior. The number of created fractures (propped and unpropped) far exceeds the number of perforations. This indicates the formation of complex fracture networks likely caused by the interaction of the hydraulic fracture with natural fractures and bed boundaries during propagation. A heel-side bias of fluid and proppant distribution within a stage was also observed. The effect of inter-stage stress shadowing on fracture growth could also be inferred.
Complex fracture networks are formed when hydraulic fractures grow in naturally fractured reservoirs. Current planar fracture models are inadequate for capturing the effect of natural fractures on fracture propagation and addressing the important question of optimum fracture spacing and well spacing. Stress interference due to three-dimensional fracture networks can result in intricate fracture geometries, which are usually neglected by fracture models. In this paper, we present a three-dimensional hydraulic fracturing simulator that models the deformation and stress fields induced by both the dilation and shear failure of all existing and propagating hydraulic or natural fractures. It is shown that the simulator allows us to capture the complex fracture geometries, and microseismic signatures often observed in heterogeneous and naturally fractured rocks. Fracture geomechanics is modeled in a computationally efficient manner using a fully three-dimensional displacement discontinuity method. The simulator captures the physics of fracture growth, fracture turning, fluid distribution in fracture networks, and the intersection of hydraulic fractures with pre-existing natural fractures. The model captures the interaction between multiple branches of a hydraulic fracture (stress shadow effect). The model also simulates the shear failure of hydraulically disconnected natural fractures to simulate microseismic activity and can account for the effect of shear failure and slippage along bed boundaries and along natural fractures on hydraulic fracture propagation. The effect of pre-existing natural fracture density and orientation on the geometry of the fracture network generated is systematically studied. It is shown that natural fractures play an important role in determining the propagation direction of hydraulic fractures and this effect is quantified. At high natural fracture density, the propagation direction of a hydraulic fracture is dominated by the orientation of natural fractures rather than the far field stress magnitude and direction. The density of the natural fractures also affects the complexity of the final created fracture geometry.
Summary In ultralow-permeability reservoirs, communication between wells through connected fractures can be observed through tracer and pressure-interference tests. Understanding the connectivity between fractured horizontal wells in a multiwell pad is important for infill well drilling and parent-child well interactions. Interwell tracer and pressure-interference tests involve two or more fractured horizontal wells and provide information about hydraulic-fracture connectivity between the wells. In this work, we present an integrated approach based on the analysis of tracer and pressure interference data to obtain the degree of interference between fractured horizontal wells in a multiwell pad. We analyze well interference using tracer (chemical tracer and radioactive proppant tracer) and pressure data in an 11-well pad in the Permian Basin. Changes in pressure and tracer concentration in the monitor wells were used to identify and evaluate interference between the source and monitor wells. Extremely low tracer recovery and weak pressure response signify the absence of connected fractures and suggest that interference through matrix alone is insignificant. Combined tracer and pressure-interference data suggest connected fracture pathways between the communicating wells. The degree of interference can be estimated in terms of pressure response times and tracer recovery. An effective reservoir model was used to simulate pressure interference between wells during production. Simulation results indicate that well interference observed during production is primarily because of hydraulically connected fractures. Combined tracer and pressure-interference analysis provides a unique tool for understanding the time-dependent connectivity between communicating wells, which can be useful for optimizing infill well drilling, well spacing, and fracture sizing in future treatment designs.
In unconventional reservoirs, the presence of natural fractures coupled with high pore pressures leads to the creation of complex fracture networks. During drawdown, the fracture network experiences large changes in the stresses which can affect the fracture conductivity, and hence the production rate. We present a workflow to find an optimum drawdown strategy in which the fractures can remain conductive while maintaining a high enough drawdown to maximize production. A fully coupled geomechanical reservoir simulator is developed to simulate production from complex fracture networks. Flow in the fracture and reservoir domains is solved in two separate conforming meshes which are coupled through matrix-fracture transfer indices. The complex fracture network is represented as an explicit discontinuity in the reservoir domain which is essential to capture the stress variations in the vicinity of the fractures due to reservoir depletion and fracture closure. The fracture closure process is modeled dynamically using the Barton-Bandis contact relationship, and the fracture conductivity is determined using the fracture width and proppant concentration. This model is used to study the impact of drawdown strategy on fracture conductivity and well productivity. It is observed that the estimated ultimate recovery (EUR) from complex fracture networks depends upon the connected fracture conductivity and the applied drawdown. A conservative drawdown strategy maintains the fracture conductivity for a longer period but results in a lower initial production rate. As the drawdown is increased, the unpropped fractures close and can cause a large portion of the fracture network (the part behind the closed segment) to get disconnected from the wellbore. This reduces the available fracture area for production. Although an aggressive drawdown strategy results in higher initial production rates, it can lead to faster fracture closure, in turn resulting in a lower EUR. Impact of drawdown strategy on productivity is analyzed at different fracture closure rates. We show that the optimum choke management strategy depends on the sensitivity of the fracture conductivity to stress. A coupled geomechanical reservoir model is presented that can simulate production with dynamic fracture closure in complex fracture networks to quantify this effect.
During hydraulic fracturing, natural fractures and bedding planes can intersect with growing hydraulic fractures and form complex fracture networks. This can result in the flow of fluid and proppant in convoluted fracture pathways with highly variable fracture width and height. Existing models of hydraulic fracturing assume a planar fracture geometry and are unable to simulate proppant placement in such complex networks. In this work, we investigate proppant transport in growing fracture networks using a fully three-dimensional, geomechanical fracture flow, network model with the ability to simulate proppant transport. A three-dimensional hydraulic fracturing simulator developed using the displacement discontinuity method is coupled with a network model for proppant transport. The simulator captures the effect of proppant concentration, fracture width, and fluid rheology on proppant transport. The equations for the fracture network geomechanics, the fluid flow, and the proppant transport are solved in a coupled manner. This provides an accurate estimation of both the fluid pressure and the proppant distribution as the fracture network grows. The geometry of each fracture segment affects the flow distribution in the network. Simulations are then conducted to study the redistribution of proppant as it settles in the fracture network during shut-in to get the final proppant distribution in the network. It is observed that changes in the in-situ stress due to heterogeneity and the stress-shadow induced near the intersection of a hydraulic fracture and a natural fracture may reduce the fracture width and suppress the ability of the proppant to move into the natural fracture. In low permeability formations, due to low leak-off rates, the proppant almost always forms a proppant bank at the bottom of the fracture during shut-in. For planar fractures, proppant settling may disconnect the conductive proppant bank from the wellbore, isolating the productive propped fracture from the wellbore. This problem is exaggerated in the case of fracture networks, where every intersection point between fractures can potentially act as a bottleneck for the flow of produced hydrocarbons. The increase in the surface area due to hydraulically connected natural fractures increases fluid leak-off, reduces the average width of the fracture network, increases proppant concentration, and increases the likelihood of proppant bridging. This work allows us to improve our understanding of proppant placement in three-dimensional, mechanically interacting, complex fracture networks. By coupling geomechanics with proppant transport in fracture networks, it is now possible to study the impact of the stress shadow on proppant placement in natural fractures. The results will assist in improving hydraulic fracture design for naturally fractured reservoirs.
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