Pressure Variations Inside the Hydraulic Fracture and Their Impact on Fracture Propagation, Conductivity, and Screenout
- A. Ali Daneshy (Daneshy Consultants Intl.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- February 2007
- Document Type
- Journal Paper
- 107 - 111
- 2007. Society of Petroleum Engineers
- 2.2.2 Perforating, 4.1.2 Separation and Treating, 1.8 Formation Damage, 1.2.3 Rock properties, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.5.8 History Matching, 5.2 Reservoir Fluid Dynamics, 2.5.1 Fracture design and containment
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Field measurements of fluid pressure inside hydraulic fractures have shown rapid pressure declines along the fracture length. The consequence of this pressure profile is rapidly tapering fracture width. This means that a disproportionate volume of fluid and proppant injected inside hydraulic fractures remains near the wellbore, thus creating excessive near-wellbore and substantially less far-field fracture conductivity. This explains why history matching of oil well production figures yields much lower effective fracture lengths than when the same exercise is performed for gas wells, as oil wells require higher fracture flow capacity because of their higher permeability.
The rapid tapering of the fracture width also restricts the movement of the proppant inside the fracture, causing its accumulation near the wellbore. As the treatment progresses, and if sufficient proppant volume has been injected inside the fracture, the near-wellbore segment of the fracture can begin to fill with proppant, thus reducing the open width available for further movement of the fluid. Essentially, accumulation of proppant near the wellbore reduces the fracture width available for fluid flow, which then results in higher frictional pressure losses inside the fracture, further skewing the pressure distribution and eventually leading to screenout.
Over the last two decades, the industry has been gradually recognizing the complexity of the theory and practice of hydraulic fracturing. Simple theories of tensile fracturing (Haimson and Fairhurst 1967) evolved successively into concepts of near-wellbore tortuosity (Aud et al. 1994), of the presence of branches and shear fractures (Weijers et al. 2000), and of off-balance growth (Daneshy 2003). The hydraulic fracture is now viewed as extending under a mixture of tensile and shear forces and containing numerous branches, with the extension occurring randomly around the fracture tip and highly influenced by local inhomogeneities and planes of weakness. Randomly distributed proppant packs forming behind narrow shear fractures are now offered as alternatives to simple viscosity-dominated proppant transport models (Daneshy 2005). The natural consequence of these developments is the recognition that our simple models of pressure distribution inside the fracture also need revision and re-evaluation. This paper extends the new fracturing concepts into analysis of fluid pressure variations inside the fracture and reviews their impact on fracture shape, fracture conductivity, analysis of post-frac treatment pressure analysis, and the causes of screenout, as well as the other major application of hydraulic fracturing, namely in-situ stress measurement.
Fluid pressure variations observed during a fracturing treatment have always been very complex and unpredictable. Most hydraulic fracturing theories assume the fluid pressure to be relatively constant inside the fracture, except for the small region near its tip. Under this condition, tensile fracturing models coupled with energy balance equations predict that fluid pressures tens or a few hundred psi in excess of the least in-situ principal stress will be sufficient to extend a hydraulic fracture. These same models predict the extension pressure to be relatively flat or slightly decreasing. Yet actual hydraulic fracturing pressures sometimes vary by several thousand psi. One explanation offered for such pressure variations has been fracture containment (Nolte and Smith 1979). The hypothesis offered is that fluid pressure in a vertically contained fracture would increase during the treatment and that constant or decreasing pressure means the fracture is experiencing excessive vertical growth. However, in spite of its simplicity and appeal, this theory cannot explain how the enormous energy contained in the pressurized fluid is consumed inside the fracture, nor how the formation can resist the very large stresses created by these pressure increases.
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