Zhou, Jian (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zeng, Yijin (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Zhang, Baoping (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering) | Shen, Boheng (Missouri University of Science and Technology) | Zhou, Jun (State key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering)
ABSTRACT: The multi-staged fracturing is becoming one of the key strategies for the shale gas development worldwide. The impact of stress shadow and natural fractures on fracture could cause unexpected fracture geometry in this case. The staged fracture initiation and fracture geometry during fracturing in shale are investigated through a series of tri-axial fracturing experiments. The shale blocks made by fresh shale outcrop were tested with a varied of perforation intervals as 80mm, 120mm, 160mm, 200mm, respectively. The testing results demonstrated that the multi-fracture interference occurred and it caused complex unbalanced facture geometry when the notch interval was 80mm and 120mm. By real-time diagnosis with microseismic(MS) data, we found that due to the double effect of stress shadow and natural fracture, the second fracture tends to be much shorter compared with the first fully developed fracture. Meanwhile, the direction of the second fracture tends to be a diverging fracture. However, the obvious effect of stress shadow was not found in our tests when the notch interval was 160mm and 200mm. At last, a simple mode for effective stimulation of reservoir volume (ESRV) calculation based on MS data was introduced to compare individual ESRV for different fracture geometries.
With the development of shale gas in the last decades, horizontal multi-stages hydraulic fracturing have more and more become valuable technique for stimulation of shale reservoirs. In naturally fractured shale reservoirs, the widely held assumption that the hydraulic fracture is an ideal, simple, straight, bi-wing, but planar feature is untenable because of natural fractures, faults, bedding planes and stress contrasts. In this kind of shale reservoirs due to interaction with natural fractures or frictional interface, the fracture may propagate asymmetrically or in multiple strands or segments.
The presence of natural fractures alters the way the induced fracture propagates through the rock. The early studies (Zoback, 1977; Daneshy, 1974; Lamont and Jessen, 1963; Blanton, 1982) have shown that the propagating fracture crosses the natural fracture, turns into the natural fracture, or in some cases, turns into the natural fracture for a short distance, then breaks out again to propagate in a mechanically more favorable direction, depending primarily on the orientation of the natural fracture relative to stress field. A fracture interaction criterion to predict whether the induced fracture causes a shear slippage on the natural fracture plane leading to arrest of the propagating fracture or dilates the natural fracture causing excessive leak-off was proposed based on mineback experiments (Warpinski and Teufel, 1987). A simple criterion for crossing was proposed by applying a first order analysis of the stresses near a mode I fracture impinging on a frictional interface oriented normal to the growing fracture (Renshaw and Pollard, 1995). According to their work, crossing will occur if the magnitude of the compression acting perpendicular to the frictional interface is sufficient to prevent slip along the interface at the moment when the stress ahead of the fracture tip is sufficient to initiate a fracture on the opposite side of the interface. Scaled laboratory experiments and numerical tests proved that high flow rate or viscosity yields fluid- driven fractures, while low flow rate just opens an existing fracture network (Beugelsdijk and de Pater, 2000, 2005). Laboratory scale tests also found that interaction of a hydraulic fracture with a natural fracture depended heavily on the stress state, inclination of the natural fracture with respect to the hydraulic fracture, and the strength of the natural fracture (Zhou et al., 2010 and Ingraham et al., 2016). For the case of natural fractures in shale are mineralized, researchers embedded planar glass discontinuities into a cast hydrostone block as proxies for cemented natural fractures and used these blocks to perform tests to examine the effects of cemented natural fractures on hydraulic fracture propagation. Their results show that obliquely embedded fractures are more likely to divert a fluid-driven hydraulic fracture than those occurring orthogonally to the induced fracture path (Olson et al., 2012).