It is an established fact that the Canyon Sand Formation in the Val Verde Basin must be fracture stimulated to exploit the reservoir's potential. However, in the past, the degree of stimulation required has been a judgement call at best. Due to recent results from an industry consortium dealing with conductivity, it became obvious that many past stimulation designs were inadequate. Changes in fracturing fluids, as well as proppant selection, concentration, and placement, have led to an improved design.

Past treatments were insufficient in fracture half-length and conductivity. These treatments have now been modified to double the fracture half-length, and to increase the conductivity six-fold. These design changes are necessary to overcome fluid damage and long-term conductivity deterioration. Computer simulated fracturing programs have been used to develop improved designs. When implemented in the field, these designs have proven to increase profitability through post-frac production results.

Although previously reported laboratory work has addressed the topic of in-situ fracture conductivity, these findings were not substantiated with actual production results. Therefore, a case study of twenty four wells located in Sutton County, Texas was performed to determine the actual effect of fracturing fluid type on well performance. A comparison of post-frac well production indicates that different fracturing fluids can dramatically effect a well's producibility. This case study supports the consortium's findings, that different fracturing fluid types create varying levels of permeability impairment.

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