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).
Zhou, Jian (Sinopec Research Institute of Petroleum Engineering) | Zeng, Yijin (Sinopec Research Institute of Petroleum Engineering) | Jiang, Tingxue (Sinopec Research Institute of Petroleum Engineering) | Zhang, Baoping (Sinopec Research Institute of Petroleum Engineering) | Zhang, Xudong (Sinopec Research Institute of Petroleum Engineering)
This reservoir is a tight gas field and the target sand stone zones are generally staged fracturing treated at depths of roughly 1500 to 2800 meter. Knowing the direction or azimuth of the fracture orientation is important in development of this low permeability reservoir with horizontal wells. The paper presents surface tiltmeter hydraulic fracturing mapping results of 15 stages treatment in two horizontal wells at the same operational period. The two wells are part of a cluster of six horizontal wells located in North of Yulin, Shanxi province. Application of this technology is important in this tight gas field where fracture stimulation is a key method for production enhancement and reservoir development. This was the first deployment of tiltmeter mapping on a cluster of horizontal wells, and several modifications were made for the standard procedures. Using an array of 54 Surface Tiltmeters, the mapping was performed on all 15 treatments with the average perforation depths of TVD 2540 to 2545m at each horizontal section to determine hydraulic fracture azimuth and fracture length, respectively. For the first horizontal well R-3H, the tiltmeter mapping results show that, the azimuth of fractures is between N53 °E and N71 °E, and the fracture half length for stages fractures is between 112m and 149m. For the second horizontal well R-5H the tiltmeter mapping results show that, the azimuth of fractures is between N67 °E and N76 °E, and the fracture half length for stages fractures is between 107m and 142m. Besides, in the well R-3H from stage 7 to stage 9, the horizontal volume component of fractures, increased from 17% to 34%, as well as in the well R-5H from stage 5 to stage 9, the horizontal volume component of fractures significantly increased to 69% from 20%. Meanwhile, the production of the two wells after the fracturing was the first and second among the cluster of the six horizontal wells, respectively. Thus, by using the synchronous fracturing technology, we believe that it not only improved the complexity of the staged fractures between the two wells but also led to a better production enhancement.