Stress fractured reservoir

Gutierrez, M., Makurat, A., Cuisiat, F., Tunbridge, L. and Jostad, H.P. 1995. In-situ stress variation in fractured reservoirs. Project Summary Reports, Norwegian Petroleum Directorate, Stavanger, Norway, pp. 231-245. 

Heffer, K.J., Last, N.C., Koutsabeloulis, N.C., Chan, H.C.M., Gutierrez, M. and Makurat, A. 1994. The influence of natural fractures, faults and earth stresses on reservoir performance - geomechanical analysis by numerical modelling. In North Sea Oil and Gas Reservoirs - 111, pp. 201-211. 

Knowledge of the stresses in a reservoir is essential to get information about the pressure at which initialization of a fracture can take place. The upper bound of the fracture initialization pressure can be estimated using a formula given... 

Flow in undisturbed rock normally is radial toward a site of lower pressure (the wellbore). The fracture crack created by high pressure injection usually forms perpendicular to the least principle stress that exists in the rock. The induced fracture intersects and disrupts the radial flow pattern such that flow becomes linear and more direct to the well. This phenomenon has been intensively examined and discussed by authors working in the discipline of rock mechanics as applied to hydrocarbon reservoirs. Hydraulic fractures created in oil and gas wells grow mainly vertically, parallel to the wellbore as depicted in Figure 1 and extend on either side of the perforated wellbore as "wings11 (7-11). 

Melt fracture occurs when the rate of shear exceeds a critical value for the melt concerned at a particular temperature (that is, the critical shear rate ). There is a corresponding critical shear stress and the relevant point on the flow curve (or the shear rate-shear stress diagram) is known as the critical point. It is believed that it is reached in the die entry region (that is, where material is being funnelled from the die reservoir into the capillary of a capillary rheometer)—which, in an extruder, corresponds with the point at which melt moves into the die parallel portion of the die. Some further complicating effects may occur at the wall of the die. 

Lorenz, J.C, 1988. Results of the multiwell experiment. In situ stresses, natural fractures and other controls on reservoirs. EOS, Trans. Am. Geophys. Union, 69 817-826. 

Fig. 14. Relationships between pore-pressures, the hydrostatic gradient, the fracture pressure gradient (approximation to the minimal horizontal stress, Sf,) and the lithostatic pressure gradient (approximation to the vertical stress, S ). Pore-pressures from sea floor to base Pliocene equals hydrostatic. The yellow, dark blue and red pore-pressure trend-lines represent the pore-pressure versus depth gradients for the Paleocene-Eocene, Mid-late Cretaceous and Upper Jurassic-lowermost Cretaceous, respectively. The portion of the red trend-line below approximately 2550 m MSL equals the maximum reservoir pore-pressure trend-line of Fig. 13 and reflects the counter-pressure of the topseal controlling the pore-pressure distribution of hydraulic compartments II, III and (probably) IV.

As seen from Fig. 14 the maximum reservoir pore-pressure at the apex of hydraulic compartments II and III lie in the order of 100 bar below the minimum fracture gradient. This pressure difference (i.e., effective horizontal stress or retention capacity, R ) decreases with depth and goes below 70 bar at approximately 3500 m. 

The simulated present reservoir pressure (Fig. 5c) indicates significant decrease in effective stress, but below estimated fracture pressure (0.8-0.85 X geostatic pressure) in the Snorre field. An important factor in controlling the estimated porosities in the reservoir sands, due to the... 

All fractures generated by internal fluid overpressure are here referred to as hydrofractures. The fracture-generating fluid may be oil, gas, magma, groundwater, or geothermal water. Hydrofractures include dykes, inclined sheets, mineral veins, many joints, and the man-made hydraulic fractures that are used in the petroleum industry to increase the permeability of reservoir rocks. Hydrofractures are primarily extension fractures (Gudmundsson et al. 2001). The difference between the total fluid pressure in a hydrofracture and the normal stress, which for extension fractures is the minimum compressive principal stress, oj, is referred to as the fluid overpressure. 

The permeability in the x, y and z directions, is strongly affected by the fracture distribution and fracture dimensions. Since the fracture apertures depend on pressure in the fluid and normal and shear stresses (see equations (3) and (4)), the permeability of the reservoir (defined by its components AT,), should be treated as a... 

Hyunil Jo, EhD, Baker Hughes. 2013. Optimal fracture spacing of a hydraulically fractured horizontal wellbore to induce complex fractures in a reservoir under high-situ stress anisotropy. SPE. 16717. 

Microseismic mapping technology is rooted in the observation that when a fracture is induced into a reservoir or the bounding rock layers the in situ stress is disturbed, resulting in shear failure and subsequent "mini-earthquakes" (Walser, 2010). 

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