Summary Hydraulic-fracturing treatments have become an indispensable part of well completion in shale gasfield development. Shale formations often contain natural fractures, and complex hydraulic-fracture networks may form during a treatment. The complex fracture network is strongly influenced by the interaction between the hydraulic fracture and the pre-existing natural fractures. A criterion has been developed to determine whether a fracture crosses a frictional interface (pre-existing fracture) at nonorthogonal angles. This criterion is an extension of the one for orthogonal crossing originally developed by Renshaw and Pollard (1995). The dependence of crossing on the intersection angle is shown quantitatively using the extended criterion. The fracture is more likely to turn and propagate along the interface than to cross it when the angle is less than 90°. The validation of the criterion using laboratory experiments for various angles is described and discussed. When applied to laboratory experiments, good agreement between the criterion and experiments is observed for a wide range of angles. The criterion can be used to determine whether hydraulic fractures cross natural fractures under particular field conditions, and it has been incorporated in a hydraulic-fracture model that simulates hydraulic-fracture propagation in a naturally fractured formation.
Hydraulic fracturing treatments have become an indispensable part of well completion in shale gas field development. Shale formations often contain natural fractures and complex hydraulic fracture networks may form during a treatment. The complex fracture network is strongly influenced by the interaction between the hydraulic fracture and the pre-existing natural fractures. A criterion has been developed to determine whether a fracture crosses a frictional interface (pre-existing fracture) at non-orthogonal angles. This criterion is an extension of the one for orthogonal crossing originally developed by Renshaw and Pollard (1995). The dependence of crossing on the intersection angle is shown quantitatively using the extended criterion. The fracture is more likely to turn and propagate along the interface than to cross it when the angle is less than 90°. The validation of the criterion using laboratory experiments for various angles is described and discussed. When applied to laboratory experiments, good agreement between the criterion and experiments is observed for a wide range of angles. The criterion can be used to determine whether hydraulic fractures cross natural fractures under particular field conditions, and it has been incorporated in a hydraulic fracture model that simulates hydraulic fracture propagation in a natural fractured formation.
One of the concerns of using proppant in geothermal wells, and particularly in enhanced geothermal systems, is proppant flowback. Particulate proppant maintain post-closure conductivity in hydraulically opened fractures. If that proppant is displaced from the nearwellbore region, either due to overflushing during stimulation or flowback to the wellbore at any time, the reduced fracture width chokes the injection or production. Two intermediate-scale laboratory analogs of a propped hydraulic fracture were prepared, and fluid was flowed through a normally stressed, propped fracture into a central wellbore. The tests were conducted in a polyaxial load frame. Acoustic/microseismic activity was measured during the injection programs. In one scenario-radial flow through a transverse fracture to a wellbore-the results suggest the creation of flow channels and nominally intact propped zones around the channels, maintaining fracture aperture. In the other-linear flow through a longitudinal fracture into a wellbore-there was substantially more proppant removal. The measurements have shown a greater tendency for proppant flowback in a linear flow situation (proppant movement is kinematically more restricted for radial convergent flow). The pressure gradients causing flow are exceedingly small and restraining flowback will be difficult. Convergent flow relationships could be an issue for injector wells, which will experience fluid flowback during hard shutdowns.
When a well is hydraulically fractured, the propagation of the fracture away from the wellbore is dictated by the far field stresses in the reservoir. However, the fracture initiation from the wellbore depends strongly on the near wellbore stress state created by drilling the well. Misaligned fracture initiation and propagation planes can reduce the wellbore-to-reservoir connectivity causing operation failure and high post fracturing skin.Currently creating multiple fractures along a horizontal openhole requires mechanical isolation means such as openhole packers or sand plugs. They can be costly and time consuming. In addition, there is no control of fracture initiation within one isolated section. Undesirable competing fractures within the zone can occur to impact the fracture length. Significant improvement can be made if the factors controlling multiple fracture initiation without mechanical isolation can be understood.Experimental work in multiple fracture initiation has been rare, controlled multiple fracture initiation is non-existent. Therefore a series of laboratory experiments was performed in a true tri-axial stress frame to investigate how multiple fractures can be initiated in a controllable fashion. In the tests, notches at specific locations along the openhole wellbore were created. The impact of the notch depth on the orientation of the hydraulically induced fractures was studied.In addition to the experiments, continuum fracture mechanics modeling using finite element was also conducted to rationalize the experimental observations of fracturing initiation process in the rock.The results of block tests provided new insight in multiple fracture initiation. By monitoring the real time acoustic emission events, the sequence of fracture creation as wellbore pressure increased was visualized. The finite element modeling gives simple criteria to explain the observed orientation of initiated fracture as a function of notch depth. IntroductionThe productivity of horizontal wells may be enhanced by inducing multiple hydraulic fractures along the wellbore. The propagation of a fracture away from the wellbore eventually is determined by the far field stresses in the reservoir. Assuming isotropic homogeneous formation properties, a longitudinal fracture will propagate along the axis of the horizontal wellbore when the well is drilled into the maximum principal horizontal stress (σ H ). A transverse fracture will propagate if the well is drilled into the minimum principal horizontal stress (σ h ). However, the fracture initiation from the wellbore is more complex (Daneshy 2009). It depends not only on the reservoir stresses orientation, but also is influenced by the near wellbore local stress state due to the drilling of the well. The mechanical properties of the rock, the surface condition of the wellbore wall, the rate of pressurization, and the physical properties of the fracturing fluid also play important roles in fracture initiation direction. Fracture initiation, though does not necessarily alter the fa...
Highly plastic and over-pressured formations are troublesome for both roller cone and PDC bits. Thus far, attempts to increase penetration rates in these formations have centered around re-designing the bit or modifying the cutting structure. These efforts have produced only moderate improvements. This paper presents both laboratory and field data to illustrate the benefits of applying a mirror polished surface to the face of PDC cutters in drilling stressed formations. These cutters are similar to traditional PDC cutters, with the exception of the reflective mirror finish, applied to the diamond table surfaces prior to their installation in the bit. Results of tests conducted in a single point cutter apparatus and a full-scale drilling simulator will be presented and discussed. Field results will be presented that demonstrate the effectiveness of polished cutters, in both water and oil-based muds. Increases in penetration rates of 300400% have been observed in the Wilcox formation and other highly pressured shales. Typically, the beneficial effects of polished cutters have been realized at depths greater than 7000 ft, and with mud weights exceeding 12 ppg. Introduction Historically, drill bits employing polycrystalline diamond to medium-hard formations, with low abrasivity. Nearly 70% of the formations drilled with PDC bits are shales, but successful applications in carbonates, evaporites, mud and siltstones, and sandstones are also common. Extensive studies performed in laboratory wellbore simulators have also provided important data for the proper geological applications and drilling practices that optimize drilling with PDC bits. Even though a PDC bit is deemed appropriate to the targeted formation, efficient, and thus economic, drilling performance depends on an optimum combination of bit design, operational practices, mud chemistry and hydraulics. Formations that can be successfully drilled increase steadily as knowledge is advanced in all these areas. Paradoxically, PDC bits occasionally perform unsuccessfully in formations they would seem to be ideally suited to drill. The U.S. Gulf Coast is one region where this is known to occur, even though the formations are not exceptionally strong or abrasive. There, the typical problem is the severe drop in the rate of penetration (ROP) experienced when drilling deep shale, especially with heavily weighted muds. These types of rock should be well suited to the shear cutting action of PDC bits, but surprisingly, PDC, as well as roller cone bits, have proven to be less than effective in drilling these formations. Increasing weight-on-bit early in the drilling cycle to reach an acceptable ROP is often unsuccessful, resulting in the bit being pulled prematurely. Examination of the bit often reveals no sign of balling or cutter damage, despite the application of heavier weight. P. 277
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