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The New and Improved Marble Falls: A Fracture-driven Resource Play

Ulysses Hargrove¹, Craig Adams¹, Beau Berend¹, Mike Grace¹, and Mike Mullen¹

¹Newark E&P Operating


"The Marble Falls play in the Fort Worth Basin and Bend Arch of Texas is a new, highly economic oil play that modern drilling and completion techniques have resurrected from an old lackluster trend. Deposition of the Lower Pennsylvanian Marble Falls Formation (MBLF) occurred relatively early in the Ouachita orogenic cycle during initial subsidence of the Fort Worth (foreland) Basin and prior to flexure of the Bend Arch (forebulge). The MBLF was deposited in various settings across a regional carbonate ramp and thus comprises multiple facies in outcrop and the subsurface. In the current fairway in Jack and Palo Pinto counties, the formation consists of spiculitic siltstone, siliceous mudstone, fossiliferous siltsone, and micritic limestone lithofacies. Matrices are generally microcrystalline and tightly cemented, yielding very low matrix porosity and permeability. Image logs and core analyses reveal that the reservoir consists of an intricate, multi-scale network of natural, lithology bound fractures (LBF) with vertical dimensions on the *m- to meter-scale. Production trends are atypical of most fracture-dominated reservoirs, however, and are strikingly similar to resource plays, with high initial rates and protracted hyperbolic declines.

MBLF production is determined both by the abundance of natural fractures and by their orientations. LBF abundance appears to be controlled by a unique confluence of lithology and tectonic position. They are most abundant near the crest of Bend Arch where flexure was greatest during subsidence of the basin and migration of the forebulge. High LBF density is also generally restricted to the spiculitic siliceous siltstone lithofacies, suggesting that high-silica content was a controlling factor in fracture generation and/or preservation. LBF orientations are largely related to Ouachita convergence, but show a range of strikes. Production is greater in wells where LBF orientations are at high angles to the present-day direction of the maximum horizontal compressive stress (*Hmax), and progressively diminishes as orientations approach *Hmax. This is attributed to increased connectivity of LBFs during hydraulic fracture treatment, because hydraulically induced fractures propagate parallel to *Hmax and can connect more LBFs if they are oriented at high angles to *Hmax and induced fractures.

Image logs are integral to developing an understanding of the MBLF naturally fractured reservoir. However, 3D seismic attributes are being evaluated for predicting fracture density and orientation, and thus production potential, ahead of the drill bit. The present fairway is largely defined by legacy assets of the original players, but the coincidence of tectonic and lithologic factors that control production extends well beyond the current areas under development, and operators are working to define the extents of the resource play.


AAPG Datapages/Search and Discovery Article #90190©AAPG Southwest Section Annual Convention, Midland, Texas, May 11-14, 2014