The Marble Falls Tight Oil Play: A New Idea in an Old Basin

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

¹Newark E&P Operating

Abstract

The Marble Falls tight-oil resource play is a prime example of a new highly economic play in a mature basin. The Morrowan-age Marble Falls Formation (MBLF) was deposited during incipient Ouachita orogenesis, during early subsidence of the Fort Worth Basin and flexure of the Bend Arch. The 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. Within the present fairway in Jack and Palo Pinto counties, TX, the MBLF comprises primarily spiculitic siliceous siltstone, mudstone-claystone, crinoidal siltstone, and micritic limestone. High silica content and low matrix porosity and permeability in the spiculitic siltstone facies make it uniquely conducive to hosting ubiquitous small-scale lithology-bound fractures that constitute the reservoir.

Although thousands of older wells penetrate the MBLF, modern open-hole logs and mudlogs are sparse and almost no core data exist. However, owing to the Barnett Shale and new MLBF plays, modern logs (triple combo, image, cross-dipole sonic), whole- and side-wall cores, and analytical data from cuttings have been acquired from thousands of recent wells in the basin. These new data have greatly enhanced the ability to map and understand the reservoir.

Public sources show >7,000 'MBLF' wells across 15 counties, but in an extensive effort we have identified < 2,400 bona fide historical MBLF producers. Because the MBLF has a reputation of being wet, many operators targeting shallower zones and operators targeting conventional traps in the MBLF would only drill a few feet into the formation. Most historic wells were completed in the MBLF only when the primary objective was not present or not productive. Traditional open-hole completions with small acid jobs achieved 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 has increased the average EUR for vertical wells from the historic 32 MBOE up to present 135 MBOE per well, which together with low D&C costs and high oil and NGL prices generate rates of return in the upper double-digits. Horizontal wells show less favorable economics than vertical wells, although several operators are still experimenting.

The MBLF has evolved from a back-water marginally economic bail-out target to a highly economic tight-oil and liquids-rich natural gas resource play over a period of only a few years as a result of the modern geologic and engineering practices.

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