Stimulation of a naturally-fractured, low permeability, low-pressure 2000-foot horizontal well in a low permeability reservoir and in-situ stress environment requires careful stimulation fluid design to minimize the capillary retention of treatment fluids. Therefore, a systematic approach to stimulation design using N2, CO2, and N2-foam was used to select one which is most efficient. Stimulation modeling was used to evaluate fracture geometry with particular concern for the minimum pressure rise above parting pressure required for height growth during frac fluid injection. Up to seven zones along the horizontal wellbore are available for stimulation. Each zone was ranked and pre-frac tested to establish pre-frac permeabilities. A N2 and N2-foam data frac was performed in one zone to establish leakoff characteristics. Subsequently, N2, CO2, and N2-foam treatments were performed on a 400-foot zone to evaluate the effectiveness of CO2 versus N2 frac fluids. Both the data frac and subsequent stimulations were evaluated in the two least productive intervals in order to use the preferred fluids in the best zones in the reservoir. The post-treatment decline curves for N2 and CO2 indicate a CO2-based fluid treatment should be performed in the most productive interval to achieve maximum success. Results of the stimulation conducted are presented along with discussion of improvement ratios and potential utility to other horizontal drilling projects.

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