The main goal in stimulating shale formations is to maximize the reservoir contact with the hydraulic fracture face. In order to achieve this goal current practices include pumping low-viscosity fluids at high rates with small mesh proppant cycles. A novel approach was used in a well in the Eagle Ford shale to enhance the stimulated area. This technique, called "relax-a-frac", was developed by an operator/service company alliance during the exploration phase. Real-time microseismic hydraulic fracture monitoring (RT HFM) indicated that the conventional slickwater treatments were not providing adequate lateral coverage across the planned stage. To address this issue, controlled changes were made to the pumping schedule, and the effects were evaluated using RT HFM. The results indicated that relax-a-frac proved to be highly successful in increasing the estimated stimulated volume (ESV) in this formation and area.In relax-a-frac, a part of the stimulation treatment was pumped (usually pad plus proppant slugs), followed by an extended shutdown to relax the formation. Once the surface pressure reached a predetermined value, the treatment was resumed, as per program, with monitoring for microseismic activity. The microseismic activity observed during the second part of the treatment showed a significant increase compared to that of the first part, with improved lateral coverage. The resultant ESV increased significantly from this technique as compared to any other specific changes tried on these wells. Production log results from Well 1 showed a definitive correlation between production contribution and the ESV derived from HFM analysis. This paper documents that this novel approach more effectively stimulates the Eagle Ford shale when compared to the typical treatment designs. Conclusions from a detailed comparison of the well performance and its relation to the treatment design are included.

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Unconventional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic fracture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can give a better understanding to the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region were mapped in real time with a 3-D stimulation viewer software package. One well employed techniques standard to the area -while some experimental fracture techniques were tested on the other. A general east-west orientation of planar fracture geometry was found with a maximum fracture event length of 800 feet. The planer fracturing scheme is consistent with low amounts of acoustic anisotropy recorded. Increasing treating and bottom hole pressures with time observed in this study indicate fracture length growth for each stage. 11 and 12 stages were chosen for the two well completion program based on data from an open hole logging and geomechanics.Some experimental fracturing techniques were tested including longer pump times, larger sand volumes, high viscosity fracture fluids, re-fracturing for re-orientation, using temporary, degradable fiber plugs between stages, and plugging of stages with ball sealers. Perforation entry by stage was effective and some stages could possibly be eliminated to save cost. There is not a direct correlation between pump time, sand volume, and stage height. Ball sealers were not an optimum method for closing off a stage for fracturing, but there is evidence that degradable fiber plugs could be a cost saving option between stages. This paper outlines in more detail the observations from hydraulic fracture mapping in this area. Regional BackgroundThis area of study includes 3000 vertical feet of fluvial and marine sands located in the Rocky Mountain region of the United States. (Figure 1) The formation contains natural fractures, laterally restricted lenticular sandstones, and tight brittle sands. The main natural gas reservoir interval is from 5000 to 8500 feet. The productive sands have an average porosity of about 7% and permeability is in the micro-Darcy range. The first well was drilled in this region of the Rocky Mountains in 1955. In the late 1990's the discovery of increased production by fracturing lenticular sands has made this a profitable area. Due to the nature of these tight sands -wells can be located in closer proximity without lowering the production rates of neighboring wells. Wells are currently drilled on 10 acre density. Much of the area uses directional drilling from pad wells to reduce surface damage.