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Using Surface Curvature and Mud Gas Data to Predict Liquid Hydrocarbon Production in the Barnett Shale, Fort Worth Basin, TX

Donny Loughry¹ and Andy Stephens²
¹Geologist, Pioneer Natural Resources, 5205 N. O’Connor Blvd., Suite 200, Irving, TX 75039
²Geophysicist, Pioneer Natural Resources, 5205 N. O’Connor Blvd., Suite 200, Irving, TX 75039

The magnitude and orientation of the curvature attribute extracted along a horizon picked on the base of the lower Barnett Shale (northern Fort Worth basin “Combo Play”, northern Wise and southern Montague counties) can be used as an approximation for the strike and density of natural fracture swarms present in the reservoir. Fractures in the Fort Worth Basin are developed within the rock in a number of different ways, each type exhibiting slightly different preferred orientations. Fractures formed as a response to hydrocarbon generation and expulsion exhibit a preference to parallel the regional maximum horizontal stress direction prevailing at the time of maturation. Fractures formed in response to differential compaction of sediments deposited atop an unconformity have orientations that diverge from the direction of SHmax, forming instead parallel to the axial plane of the folded or curved surface. Likewise, those sediments that were subjected to regional post-depositional stresses will exhibit fracture orientations parallel to the SHmax direction prevailing at the time of the causative event. In any of the three cases, if the fracture set is oriented parallel or subparallel to the present day principle horizontal stress, a horizontal well intersecting them will encounter these fractures in an open or semi-open state. To help confirm these ideas, down-hole and surface microseismic, lateral image logging, radioactive/chemical tracers, and formation breakdown pressures were used to verify fracture density and orientation along the lateral at a test location in Wise County, TX. Additionally, the frequency of the lateral variability in reservoir character observed in these measurements was used as a guide in order to gauge the proper grid spacing of the curvature attribute at the base of the reservoir.

Mud gas curve analysis reveals that sections of the laterals that encounter open fractures show a larger proportion of heavy gases compared to sections that encounter fractures that are presumed closed based on the curvature attribute. Examining lateral footage of heavy gas shows (hereafter referred to as ‘shale pay’) and the quality of curvature azimuth yields a mathematical relationship that can be used to predict oil production pre-drill. With a median relative error of only ±30% (median absolute error of ±1905 Bbls), the results of this study have had implications for lateral length, well orientation and for high-grading geographic areas within the Barnett Combo Play.


AAPG Search and Discovery Article #90164©2013 AAPG Southwest Section Meeting, Fredericksburg, Texas, April 6-10, 2013