No abstract

Field observations show that hydraulic fracture growth in naturally fractured formations like shale is complex. Preexisting discontinuities in shale, including natural fractures and bedding, act as planes of weakness that divert fracture propagation. To investigate the influence of weak planes on hydraulic fracture propagation, we performed Semicircular Bend tests on Marcellus Shale core samples containing calcite-filled natural fractures (veins). The approach angle of the induced fracture to the veins and the thickness of the veins have a strong influence on propagation. As the approach angle becomes more oblique to the induced fracture plane, and as the vein gets thicker, the induced fracture is more likely to divert into the vein. Microstructural analysis of tested samples shows that the induced fracture propagates in the middle of the vein but not at the interface between the vein and the rock matrix. Cleavage planes and fluid inclusion trails in the vein cements exert some control on the fracture path. Combining the experimental results with theoretical fracture mechanics arguments, the fracture toughness of the calcite veins was estimated to range from 0.24 MPa m 1/2 to 0.83 MPa m 1/2 , depending on the value used for the Young's modulus of the calcite vein material. Measured fracture toughness of unfractured Marcellus Shale was 0.47 MPa m 1/2 .

Shale gas reservoirs are commonly produced using hydraulic fracture treatments. Microseismic monitoring of hydraulically induced fracture growth shows that hydraulic fractures sometimes propagate away from the present-day maximum horizontal stress direction. One likely cause is that natural opening-mode fractures, which are present in most mudrocks, act as weak planes that reactivate during hydraulic fracturing. Knowledge of the geometry and intensity of the natural fracture system and the likelihood of reactivation is therefore necessary for effective hydraulic fracture treatment design. Changing effective stress and concomitant diagenetic evolution of the host-rock controls fracture initiation and key fracture attributes such as intensity, spatial distribution, openness and strength. Thus, a linked structural-diagenesis approach is needed to predict the fracture types likely to be present, their key attributes and an assessment of whether they will impact hydraulic fracture treatments significantly. Steep (.758), narrow (,0.05 mm), calcite-sealed fractures are described in the Barnett Shale, north-central Texas, the Woodford Formation, west Texas and the New Albany Shale in the Illinois Basin. These fractures are weak because calcite cement grows mostly over non-carbonate grains and there is no crystal bond between cement and wall rock. In bending tests, samples containing natural fractures have half the tensile strength of those without and always break along the fracture plane. By contrast, samples with quartz-sealed fractures do not break along the fracture plane. The subcritical crack index of Barnett Shale is .100, indicating that the fractures are clustered. These fractures, especially where present in clusters, are likely to divert hydraulic fracture strands. Early, sealed, compacted fractures, fractures associated with deformation around concretions and sealed, bedding-parallel fractures also occur in many mudrocks but are unlikely to impact hydraulic fracture treatments significantly because they are not widely developed. There is no evidence of natural open microfractures in the samples studied.

Abstract. Mounting evidence suggests that subcritical crack growth is an important mechanism for the development of natural fractures. Numerical simulations of fracture patterns are sensitive to the subcritical crack growth index, the exponent used to describe the power law dependence of crack velocity on stress intensity.

Micro seismic data and coring studies suggest that hydraulic fractures interact heavily with natural fractures creating complex fracture networks in naturally fractured reservoirs such as the Barnett shale, the Eagle Ford shale, and the Marcellus shale. However, since direct observations of subsurface hydraulic fracture geometries are incomplete or nonexistent, we look to properly scaled experimental research and computer modeling based on realistic assumptions to help us understand fracture intersection geometries. Most experimental analysis of this problem has focused on natural fractures with frictional interfaces. However, core observations from the Barnett and other shale plays suggest that natural fractures are largely cemented. To examine hydraulic fracture interactions with cemented natural fractures, we performed 9 hydraulic fracturing experiments in gypsum cement blocks that contained embedded planar glass, sandstone, and plaster discontinuities which acted as proxies for cemented natural fractures. There were three main fracture intersection geometries observed in our experimental program. 1) A hydraulic fracture is diverted into a different propagation path(s) by a natural fracture. 2) A taller hydraulic fracture bypasses a shorter natural fracture by propagating around it via height growth while also separating the weakly bonded interface between the natural fracture and the host rock. 3) A hydraulic fracture bypasses a natural fracture and also diverts down it to form separate fractures. The three main factors that seemed to have the strongest influence on fracture intersection geometry were the angle of intersection, the ratio of hydraulic fracture height to natural fracture height, and the differential stress. Simply put, the most significant finding of this research is that fracture intersection geometries are complex. Our results show that bypass, separation of weakly bonded interfaces, diversion, and mixed mode propagation are likely in hydraulic fracture intersections with cemented natural fractures. The impact of this finding is that we need fully 3D computer models capable of accounting for bypass and mixed mode I-III fracture propagation in order to realistically simulate subsurface hydraulic fracture geometries.