Wednesday, September 21, 2011

Potential Shale Gas and Shale Oil Resources of the Norte Basin


The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of State, is assessing the potential for unconventional oil and gas resources (shale gas, shale oil, tight gas, and coalbed gas) in priority geologic provinces worldwide. The authors summarize the geologic model and results of an assessment of
potential shale gas and shale oil resources of the Norte Basin, Uruguay. The Norte Basin of Uruguay is the southern extension of the ParanĂ¡ Basin of Brazil (fig. 1), and is largely covered by volcanic rocks. The main geologic structures in the basin are interpreted to be northwest-southeast trending grabens and horsts, which, if present, control the distribution of Devonian-age shale and oil and gas resources in the basin.

Devonian Shale System in the Norte Basin

The Devonian Cordobes Formation is interpreted to be the principal petroleum source rock in the Norte Basin and possible reservoir for shale gas and shale oil accumulations. The geologic attributes of the Cordobes Formation relevant to the assessment are inferred from outcrops along the southern margin of the Norte Basin (Conti and Morales, 2009; ANCAP, written commun., 2011). Thickness of the Cordobes ranges up to 160 meters (m), including as much as 60 m of organic-rich shale. Total organic carbon concentration ranges from 0.7 to 3.6 weight percent. The organic matter is predominantly Type II marine kerogen, with a contribution from Type III kerogen. Thermal maturity at outcrop averages 0.6 percent vitrinite reflectance, suggesting thermal maturity corresponding to the onset of oil generation. Basin modeling suggests that thermal maturity necessary for oil-to-dry gas transition in the Devonian is at a depth of about 3,200 m (ANCAP, written commun., 2011), which was used as the boundary between potential shale oil and shale gas accumulations in the assessment (fig. 1). Given what is known of the thermal maturity, this boundary is uncertain.

Geologic Model for Assessment

The geologic model used in the assessment of the Norte Basin assumes oil and gas to have been generated in organic-rich shales of the Devonian Cordobes Formation and to occupy matrix porosity and organic porosity in the same shales. The thermal window for gas was modeled to begin at about the 3,200-m depth, with oil as the main petroleum phase at shallower depths. Devonian shales most likely are present beneath the volcanic cover in northwest-southeast trending grabens that have been imaged with geophysical methods. The presence of Devonian organic-rich shale in the grabens, the potential matrix storage of oil or gas, and the thermal windows for oil in relation to gas are subject to significant geologic uncertainty. Shale gas and shale oil accumulations in the United States were used as geologic and engineering analogs in the assessment. Analog data from U.S. accumulations included estimated ultimate recoveries (EUR) from shale gas and shale oil wells, mean drainage areas of wells (cell sizes), and ranges of well success ratios.

Key assessment input data are listed in table 1.

Resource Summary
The USGS assessed potential technically recoverable shale gas and shale oil resources in the Norte Basin of Uruguay, resulting in total estimated mean resources of 13,361 billion cubic feet of gas (BCFG), 508 million barrels of oil (MMBO), and 499 million barrels of natural gas liquids (MMBNGL) (table 2). Of these totals, the estimated mean resource volumes are (1) Devonian Cordobes Formation Shale GasAU,11,328BCFG(range from 0 to 24,042 BCFG), and 453 MMBNGL range from 0 to 1,002 MMBNGL); and (2) for the Devonian Cordobes Formation Shale Oil AU, 508 MMBO (range from 155 to 1,081 MMBO), and 2,033 BCFG associated gas (range from 574 to 4,521 BCFG), and 46 MMBNGL (range from 12 to 106 MMBNGL). The ranges of resource estimates, particularly those for shale gas (0 to 24,042 BCFG), reflect the considerable geologic uncertainty in these assessment units.

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