The Marble Falls play in the Fort Worth Basin and Bend Arch of Texas is a new, highly economic, oil and liquids-rich gas resource play in a mature basin. The play has recently been revitalized from an old lackluster trend due largely to the application of modern technologies.

The Morrowan-age Marble Falls Formation (MBLF) lies stratigraphically above the prolific Barnett Shale source rock and locally the Comyn (Forestburg) limestone, and is unconformably overlain by the Atokan Bend Group. The Marble Falls was deposited during incipient Ouachita orogenesis, during initial subsidence of the Fort Worth (foreland) Basin and flexure of the Bend Arch (forebulge). Deposition occurred in multiple settings across a regional carbonate ramp and the formation lateral and vertical facies variations in outcrop and the subsurface. In the present fairway the formation comprises spiculitic siliceous silt-stone, siliceous mudstone-claystone, fossiliferous siltsone, and micritic limestone lithofacies. Matrices are generally microcrystalline and tightly cemented, yielding very low ma-trix porosity and permeability. Image logs and core analyses reveal that the reservoir consists of an interconnected network of natural lithology-bound fractures (LBF) with vertical dimensions on the mm- 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.

The abundance of natural LBFs and their orientations are the two primary geologic factors contributing to the effectiveness of hydraulic fracture treatments and, ultimately, production. Fracture abundance appears to be controlled by a unique confluence of lithology and tectonic position: they are most prevalent near the crest of the Bend Arch, where flexure was greatest during basin subsidence and migration of the forebulge; they are also concentrated in the spiculitic siliceous siltstone lithofacies, suggesting that high silica content was a controlling factor in fracture generation and/or preservation. The fractures exhibit a range in orientations, but the dominant set suggests that they are largely related to Ouachita convergence; subordinate orientations likely relate to Mesozoic and younger events. Production is typically better in wells where LBF orientations are at high angles to the present-day direction of the maximum horizontal compressive stress (s_Hmax), and progressively diminishes as orientations approach s_Hmax. This is attributed to increased connectivity of LBFs during hydraulic fracture treatment, because hydraulically induced fractures propagate parallel to s_Hmax and can connect more LBFs if they are oriented at high angles to s_Hmax and induced fractures.

Thousands of historic wells penetrate the Marble Falls, but until recently modern open-hole logs and mudlogs were rare and almost no core data existed. Thanks to prolific drilling in the Barnett Shale and the new Marble Falls plays, however, modern log suites are available for thousands of recent wells and conventional whole- and side-wall core data, as well as analytical data from cuttings, have been acquired. These new data have greatly enhanced the ability to map and understand the reservoir. Image logs in particular have been crucial to understanding the natural fracture system. 3-D seismic is used primarily for avoiding geologic hazards, although seismic attributes are being evaluated for predicting fracture density and orientation (i.e. production potential) ahead of the drill bit.

Since the 1950s, more than 2,400 wells have produced from conventional traps in the Marble Falls, many of which were completed only when the primary objective was not present or not productive. Traditional open-hole completions were limited to small acid jobs that achieved only modest peak production rates of 15 BOPD and 150 MCFD for an average EUR of 32 MBOE per well.

Modern vertical MBLF wells achieve significantly better performance through the use of hydraulic fracturing, which connects the natural fractures to the wellbore and creates a commercial reservoir. Stimulation designs have evolved from low-rate, low-proppant, single-stage nitrogen foam fracs to slick-water fracs with increasingly higher pumping rates, higher proppant and fluid volumes, and more stages. This evolution has increased the average EUR for vertical wells from the historic 32 MBOE to the present range of 150-250 MBOE per well in the core area. Coupled with low drilling and completion costs and high oil and NGL prices, these enhanced recoveries generate triple-digit rates of return. Horizontal wells show less favorable economics than vertical wells, although several operators are still experimenting.

The present fairway in Jack and Palo Pinto Counties in North Texas is largely defined by the legacy assets of some of the original players. However, the coincidence of tectonic and lithologic factors that contribute to high reservoir quality and high production rates extends well beyond the current areas under development, and operators are working to expand the frontiers of this resource play.