Summary Interpretation of microseismic results and attempts to link microseismic-source mechanisms to fracture behavior require an understanding of the geomechanics of the fracturing process. Stress calculations around fractures show that the area normal to the fracture surface is stabilized by a pressurized fracture as a result of increased total stress and decreased shear stress. In this area, microseisms can occur only if leakoff pressurizes natural fractures, bedding planes, or other weakness features, and source mechanisms are thus likely to show a volumetric component that has either opening or closing movement in addition to shear slippage. Conversely, the tip tensile region is destabilized by a reduction in total stress and an increase in shear stress, with the likelihood that microseisms would be generated in this region because of these changes. Such microseisms would not yet be invaded by the fracturing fluid, and events that are mostly shear would be expected. Systems with multiple fractures, such as those that are potentially created in multiperforation-cluster stages, are much more complex, but similar elements can be outlined for those as well. Source mechanisms can help delineate these different types of microseismic behaviors, but the evaluation of such mechanisms reveals that they provide no significant information about the hydraulic fracture. Whereas it would be valuable if source mechanisms could provide information about the mechanics of the hydraulic fracture (e.g., opening, closing, and proppant), calculations show that both the energy and volume associated with microseismicity are an insignificant fraction of the total energy and volume input into the stimulation. Thus, hydraulic fractures are almost entirely aseismic. The analysis of source mechanisms should concentrate on what those data reveal about the reservoir (e.g., natural fractures and faults). Integrated diagnostic studies provide more value in understanding both the microseismicity and interpretation of the microseismic results.

Interpretation of microseismic results and attempts to link microseismic source mechanisms to fracture behavior require an understanding of the geomechanics of the fracturing process. Stress calculations around fractures show that the area normal to the fracture surface is stabilized by a pressurized fracture as a result of increased total stress and decreased shear stress. In this area, microseisms can only occur if leakoff pressurizes natural fractures, bedding planes, or other weakness features, and source mechanisms are thus likely to show a volumetric component. Conversely, the tip tensile region is destabilized by a reduction in total stress and an increase in shear stress, with the likelihood that microseisms would be generated in this region because of these changes. Such microseisms would not yet be invaded by the fracturing fluid, and events that are mostly shear would be expected. Systems with multiple fractures, such as those that are potentially created in multiperforationcluster stages, are much more complex, but similar elements can be outlined for those as well. Source mechanisms can help delineate these different types of microseismic behaviors, but evaluation of such mechanisms reveals that they provide no significant information about the hydraulic fracture. While it would be valuable if source mechanisms could provide information about the mechanics of the hydraulic fracture (opening, closing, proppant, etc.), calculations show that both the energy and volume associated with microseismicity are an insignificant fraction of the total energy and volume input into the stimulation. Thus, hydraulic fractures are almost entirely aseismic. Analysis of source mechanisms should be concentrated on what that data reveals about the reservoir (e.g., natural fractures, faults, etc.). Integrated diagnostic studies provide more value in understanding both the microseismicity and interpretation of the microseismic results.

The proper interpretation of microseismic event patterns to estimate hydraulic-fracture geometries is critical for understanding well performance in unconventional reservoirs. Besides factors such as microseismic event location uncertainty, advanced interpretations should also include a proper understanding of the geomechanical context in which these events take place and the underlying mechanisms that link the hydraulic fracture to the microseismic events. In this paper we investigate the different mechanisms that can cause microseismic activity around a hydraulic fracture from the viewpoint of a 3D elasto-static model to explain the behavior of microseismic event patterns. Stress perturbations caused by the opening of hydraulic fractures, opening of extensional branch fractures, and leakoff-related effects are considered. Multiple transverse fractures as well as dilated natural fractures orthogonal to the hydraulic-fracture direction are modeled under different sets of reservoir and treatment conditions to gain insight into the importance of different mechanisms. An important observation is that stress changes alone caused by tensile opening behind the hydraulic-fracture tip cannot cause microseismic events under any set of reservoir conditions normally encountered in practice. The results indicate that tip effects, propagation of extensional branch fractures, and activation of natural fractures upon intersection should be the main drivers of microseismic activity in shale-gas plays. The modeling shows that microseismic events are expected to occur very close to the hydraulically activated fractures or planes, thus enhancing the value of microseismic monitoring. The modeling also showed that under certain conditions (critically stressed formations), the shear zone caused by tip effects can extend fairly far ahead of the fracture tip, which needs to be considered in the interpretation of fracture geometry. The presented results help to constrain and enhance the interpretation of microseismic data, from a geomechanical perspective.

Fracture growth in soft rocks and unconsolidated sands is currently modeled assuming linear elastic, brittle behavior. Observations from past experimental work show that fracture propagation in unconsolidated sands is a strong function of fluid rheology and leak off and is accompanied by large inelastic deformation and shear failure leading to high net fracturing pressures. This paper presents a new approach to modeling fracture propagation in unconsolidated sands. It is shown that the classical approach to fracture modeling that uses the stress intensity factor at the fracture tip is not suitable for unconsolidated sands. The fracture propagation criterion in our model is not based on the conventional stress intensity factor approach. Both shear and tensile failure are modeled, and both play an important role in controlling the fracture growth. Fluid loss is modeled accurately using a filtration model that accounts for a reduction in porosity and permeability induced by particles in the injected fluids as well as the possibility of filter cake formation. The model predicts considerably higher net fracturing pressures due to plastic yielding in shear around the fracture. In general there is a zone of shear failure ahead of the tip which subsequently fails in tensile mode at higher net fracturing pressures resulting in fracture propagation. Shear failure is observed to be the dominant failure mechanism in case of low efficiency fluids, with very little fracture growth in tensile mode. However, tensile fractures of considerable length surrounded by a zone of shear failure are obtained in the case of high efficiency fluids or in the case of fracture face plugging by particles present in the injected fluid. The model thus clearly shows for the first time that fractures in sands can behave quite differently under different conditions. The results of the sensitivity study conducted on the important parameters are consistent with the observations reported in experiments. The model significantly improves our understanding of the effect of key parameters such as the injection rate, fracturing fluid properties and mechanical properties of the sand on the fracturing process. It is expected that the model will find application in designing frac-pack treatments and solid waste disposal in unconsolidated formations.

Summary Selecting appropriate proppants is an important part of hydraulic-fracture completion design. Proppant selection choices have increased in recent years as regional sands have become the proppant of choice in many liquid-rich shale plays. But are these new proppants the best long-term choices to maximize production? Do they provide the best well economics? The paper presents a brief historical perspective on proppant selection followed by various detailed studies of how different proppant types have performed in various unconventional onshore US basins (Williston, Permian, Eagle Ford, and Powder River), along with economic analyses. As the shale revolution pushed into lower-quality reservoirs, the concept of dimensionless conductivity has pushed our industry to use ever lower-quality materials—away from ceramics and resin-coated proppant to white sand in some Rocky Mountain plays, and more recently from white sand to regional sand in the Permian and Eagle Ford plays. Further, we compare early-to-late-time production response and economics in liquid-rich wells where proppant type changed. The performance of various proppant types and mesh sizes is evaluated using a combination of different techniques, including big-data multivariate statistics, laboratory-conductivity testing, detailed fracture and reservoir modeling, as well as direct well-group comparisons. The results of these techniques are then combined with economic analyses to provide a perspective on proppant-selection criteria. The comparisons are anchored to permeability estimates from production history matching and diagnostic fracture injection tests (DFITs) and thousands of wellsite-proppant-conductivity tests to determine dimensionless conductivity estimates that best approach what is obtained in the field. Dimensionless fracture conductivity is the main driver of well performance because it relates to proppant selection thanks to the inclusion of the relationship of fracture conductivity provided by the proppant relative to the actual flow capacity of the rock (the product of permeability and effective fracture length), which is supported by the production analyses in the paper. The paper shows how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving this “just-good-enough” target conductivity, either through less proppant mass with higher-cost proppants or more proppant mass with lower-cost proppants, as well as mesh-size considerations. This paper does not rely on a single technique for proppant selection but uses a combination of various data sources, analysis techniques, and economic criteria to provide a more holistic approach to proppant selection.