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To intersect the maximum number of natural fractures and effectively stimulate oil-bearing zones in the fractured Eagle Ford carbonate section, an operator needed a better understanding of both the existing fractures and the matrix rock. The direction of the natural fractures needed to be determined, along with their status: open or healed. Imaging alone was insufficient for fully characterizing the fractures, and conventional logging was adversely affected by the low porosity and high organic content of the matrix.
Wellbore imaging by the FMI microimager was used to determine the directions of the natural fractures. For information on the condition of the fractures away from the wellbore, Stoneley wave data was obtained with the Sonic Scanner acoustic scanning platform. The Stoneley data clearly indicates that the natural fractures are open, which makes them good candidates for assisting production through treatment. The fast shear direction shows that induced fractures will follow the same direction as the natural fractures.
Correctly designing the fracture treatment also depended on accurate porosity and fluid evaluation. The proven CMR-Plus magnetic resonance tool was used to identify porosity in oil-bearing rock independent of the rock type, which had biased conventional measurements.
Based on the stress analysis, a lateral was positioned to both take advantage of the existing natural fracture system and maximize contact with potential reservoir sections, as determined from the CMR-Plus tool's porosity and fluid content. Swell packers were used to isolate 17 stages in the lateral for hydraulic fracturing. Because the optimal height of each targeted interval was determined from the log data, the pump size necessary was only about half of that used on neighboring wells. This successful completion achieved a 30-day average oil production of 630 bbl/d, exceeding offset wells in a frequently drilled area by 30% to 50%.
Challenge: Improve fracture stimulation of the Eagle Ford carbonate section by developing a better understanding of both the natural fractures and matrix
Solution: Run one toolstring combining the FMI formation microimager to locate natural fractures and determine their density, approximate apertures, and direction; Sonic Scanner acoustic scanning platform to verify maximum stress direction and estimate open aperture volume away from the wellbore from vertical Stoneley wave data; and CMR-Plus combinable magnetic resonance tool to locate the highest pore volume of oil unbiased by the matrix, including the generally misleading organic content
Results: Isolated 17 stages in the lateral for targeted hydraulic fracturing and achieved 30-day average oil production of 630 bbl/d, exceeding offset wells by 30%50%