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

Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics are leading to reducing completion timeby 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 that relies on a novel material blend to divert the remaining stimulation fluids to under-stimulated regions of the wellbore was developed. It is delivered downhole at high concentration levels, which are achieved by using degradable fibers to stabilize fluid fronts and prevent slug dispersion when displaced and creates diversion with a minor amount of material. The pill degrades completely after the fracturing treatment has been completed, leaving no residual formation damage. The channel fracturing technique (Gillard et al, 2010) was chosen as preferred fracturing method for use in tandem with the diverter. This technique has been reported to increase effective fracture length while reducing risk of screening-out with respect to other conventional methods.

The new diverter was used in several campaigns where where its effects were monitored with microseismic and production logs. The case studies present 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 that of its offset well treated conventionally. The signature of the diverter, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells of different characteristics.