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Multi-Scale Characterization of Faults and Fractures in the Marcellus and their Influence upon Well Performance

Stephenson, Ben; Dick, Chris; MacDonald, Courtney; Dionne, Jennifer; McGraw, Nicole; Bohn, Charles; Williams, Marty

Shell acquired acreage over the Marcellus in 2010 and since then it has been drilling and completing laterals in Tioga County. Several 3-D seismic surveys were acquired, which combined with image logs and cores has enabled structural characterization at multiple scales, from which a structural evolution was deduced.

During early mountain building, broad wavelength folding caused changes in structural thickening in the Salina Salt below the Marcellus. Small-scale natural fracturing accompanied this early folding event, with fractures oriented NNW-SSE, cemented and distributed regionally. After initial folding, large-scale ENE-WSW trending faulting occurred in the crestal areas, some places forming high angle reverse faults with throws >1000ft. In other places, these faults are manifest as zones of extensional collapse. Blocks of shale in the inter-fault regions became faulted and fractured by local fold-related stresses, commonly forming complex patterns of laterally continuous faults with small throws (<60ft) and accompanying small-scale fractures. Continued convergence caused a space problem in the vicinity of the oroclinal bend in the Appalachian fold-belt, which was accommodated in the basin by NNW-SSE and NNE-SSW strike-slip faulting, offsetting earlier crestal-collapse faults.

Early hypotheses for how each scale of structural feature could impact well performance focused attention on the long, low-offset faults, since every well intersects at least one. To overcome the general conundrum of deciphering the relative impact of the Geology versus the Stimulation, a novel method of determining the potential impact of these faults upon well performance was devised, whereby each fault is given a numerical value based on its geometrical relationship to the in-situ stress and hence the likelihood of it being stimulated during fraccing. Various trials (microseismic, tracers etc) suggest dilation rather than shear is the dominant mode of stimulation. Therefore, the sum of these values for each fault in a particular well is called the "Fault Dilation Tendency". An inverse correlation between Fault Dilation Tendency and EUR (normalized for lateral length) was discovered, suggesting that wells in faulted areas are accessing a smaller GIIP, because frac energy is being diverted into existing planes of weakness rather than stimulating virgin areas of shale. Avoiding stimulating key faults could save money and increase EUR.


AAPG Search and Discovery Article #90163©2013AAPG 2013 Annual Convention and Exhibition, Pittsburgh, Pennsylvania, May 19-22, 2013