Abstract

In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters.

Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique (Gillard et al. 2010) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods.

The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.

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