The Eagle Ford Shale was deposited during the upper Cretaceous ~ 92 – 86 m.a. Since the discovery of the Eagle Ford Shale trend it has emerged as one of the top North American unconventional plays. The Eagle Ford Shale (EFS) has had a significant impact on recent economic development in the state of Texas and ranks as the largest oil & gas development in the world based on capital invested. Approximately $30 billion was spent developing the play in 2013. Covering an area of more than 11,000 square miles, the Eagle Ford Shale is producing oil at depths of 5,000’ – 8,000’ to the northwest, grading through condensates and natural gas liquids, to dry gas at depths of 10,000’ – 15,000’ to the southeast. Shale thickness of the more organic rich lower unit, the primary target is generally greater than 200’, whereas that in the upper unit is greater than 480’. Traditionally the Eagle Ford shale was known as the source rock for south and east Texas across the gulf region. In late 2007 Petrohawk and EOG Resources began leasing acreage in Karnes and De Witt counties located south and east of San Antonio. Petrohawk was the first to prove the Eagle Ford in October 2008 with the South Texas Syndicate 241 1-H well, in La Salle County. The initial production rate was 9.1 mcf/d. In spring of 2009, Petrohawk drilled another well in McMullen County and surprisingly produced gas containing condensates and natural gas liquids. Many wells are producing over 6 MMcfg and 500 bo per day. Eagle Ford starta are overlain disconformably by the Austin Chalk formation. This contact marks geologically the Turonian/Coniacian boundary 89 m.a. Below the Eagle Ford shale lies the Buda Limestone. This contact marks a distinct shift from bioturbated wakestones of the Buda, to more organic-rich mudrocks of the Lower Eagle Ford. Regionally, Eagle Ford strata consists of two major depositional units. A lower transgressive unit dominated by dark well laminated shales, and an upper regressive unit dominated by silt, sand, and carbonates with low clay content and high clastic material makes the shale more brittle in the upper unit. The Eagle Ford Shale formation carbonate content can be as high as 70%, the higher the carbonate content and subsequently lower clay content make the Eagle Ford Shale a remarkably good formation because it is more brittle and easier to stimulate through hydraulic fracturing. Advances in horizontal drilling
technology and hydraulic fracturing have made it possible to generate fractures in rocks that would enable fluid migration into the well bore, which now made economic production possible from the Eagle Ford Shale formation. The success or failure of hydraulic stimulation, however, depends on the ability to accurately identify brittle away from ductile zones within the shale. Brittle zones are those rock layers characterized by high velocities in rocks, whereas ductile zones are layers characterized by low seismic velocity. It is necessary not only to delineate fracture zones but also to determine the richness and maturity of the shale, areas having high TOC typically yield the best production. Both Upper and Lower Eagle Ford reservoirs are generally comprised of calcareous mudstones, but depth is a major factor driving production and is likely related to pressure and geochemical factors of total organic carbon (TOC), which control petroleum conversion from kerogen.
How to produce a low permeable rock with maximum success: Most wells that produce from the Eagle Ford Shale see a decline curve of 75-80%, to combat such a high decline of production operators are testing the hypothesis of producing the well at a slower initial rate by decreasing the choke size on the well. This in fact should create a longer production curve with a less steep decline curve. So far the key drilling and completion parameters that correlate with optimal well production are well lengths approximately 5,550’ with 25 stage fracs. A total of 70,000 to 300,000 thousand barrels of water and 2 – 7 million pounds of proppant are typical completions parameters according to the Texas Railroad Commission.
Geologic Setting: During the mid-late Cretaceous, the Western Interior Cretaceous Seaway split North America into two land masses, Laramidia and Appalachia. The Western Interior Seaway extended 4,800 km from the present day Artic Ocean to the Gulf of Mexico, with a width of 1,600 km. Within this seaway the Eagle Ford Shale was deposited from the Texas Mexican border into east Texas. The Eagle ford trend forms a 80km wide and ~ 650km long, shale formation buried below the surface. The thickness and lateral distribution of the Eagle Ford Shale was controlled by pre-existing platform biologic build-ups and positive paleotopography. The San Marcos Arch is an extension of the Paleozoic Llano uplift that trends southeast – northwest and separated the Maverick Basin from the Rio Grande Embayment and the East Texas basin. A series of southwest – northeast trending fault systems developed during the Ouachita Orogeny. Other major fault zones are the Charlotte Fault zone, Balcones fault zone, Luling Fault Zone, and Fashing Fault Zone are the major fault zones throughout the south Texas area. These fault systems remained active during the deposition of the Eagle Ford Shake and led to formation depocenters. These depocenters are ideal locations for thickened sections for hydrocarbon exploration