Testing the basin-centered gas accumulation model using fluid inclusion observations: Southern Piceance Basin, Colorado

Abstract

The Upper Cretaceous Mesaverde Group in the Piceance Basin, Colorado, is considered a continuous basin-centered gas accumulation in which gas charge of the low-permeability sandstone occurs under high pore-fluid pressure in response to gas generation. High gas pressure favors formation of pervasive systems of opening-mode fractures. This view contrasts with that of other models of low-permeability gas reservoirs in which gas migrates by buoyant drive and accumulates in conventional traps, with fractures an incidental attribute of these reservoirs. We tested the aspects of the basin-centered gas accumulation model as it applies to the Piceance Basin by determining the timing of fracture growth and associated temperature, pressure, and fluid-composition conditions using microthermometry and Raman microspectrometry of fluid inclusions trapped in fracture cement that formed during fracture growth. Trapping temperatures of methane-saturated aqueous fluid inclusions record systematic temperature trends that increase from approximately 140 to 185°C and then decrease to approximately 158°C over time, which indicates fracture growth during maximum burial conditions. Calculated pore-fluid pressures for methanerich aqueous inclusions of 55 to 110 MPa (7977-15,954 psi) indicate fracture growth under near-lithostatic pressure conditions consistent with fracture growth during active gas maturation and charge. Lack of systematic pore-fluid-pressure trends

Methane bubble growth in fine-grained muddy aquatic sediment: Insight from modeling

“…For instance, pervasive opening-mode subvertical fracturing observed in the low-permeability sandstone (The Upper Cretaceous Mesaverde Group in the Piceance Basin, Colorado) emerges under the high pore-fluid pressure in response to gas generation during the rock charging (Fall et al, 2012). On a much larger scale, buoyancy-induced hydro-fracturing drives the magma intrusions and the dikes propagation (e.g.…”

Quantifying Cretaceous–Cenozoic exhumation in the Otway Basin, southeastern Australia, using sonic transit time data: Implications for conventional and unconventional hydrocarbon prospectivity

“…The Upper Cretaceous Mesaverde Group in the southern Piceance Basin was exhumed by approximately 1800 m (∼5905 ft) during the Neogene (Nuccio and Roberts, 2003;Fall et al, 2012), whereas Pennsylvanian strata in the central Appalachian Basin have been exhumed by approximately 4400 m (∼14,435 ft) since the Late Permian (Blackmer et al, 1994;Reed et al, 2005). Although the timing of exhumation from maximum burial depths in the Fort Worth Basin is a matter of some debate (e.g., mid-Cretaceous; Montgomery et al, 2005;Late Triassic;Ewing, 2006), it is agreed that the Mississippian Barnett Shale has experienced more than 1500 m (∼4920 ft) of net exhumation (Jarvie et al, 2005Montgomery et al, 2005;Ewing, 2006).…”

“…Generalized burial history reconstructions of the Williston Basin show that parts of the oil-prone Bakken Formation experienced as much as 700 m (∼2295 ft) of exhumation since the early to mid-Paleogene (Pollastro et al, 2011). In contrast to the two phases of exhumation observed in the Otway Basin, many unconventional plays in the United States appear to record only one significant exhumation event (Montgomery et al, 2005;Pollastro et al, 2011;Fall et al, 2012). The structural style of exhumation (i.e., passive margin inversion of synrift faults vs. foreland basin flexural rebound; Blackmer et al, 1994) is another key difference.…”

“…Although hot fluid flow may have contributed to thermal maturity in some areas such as adjacent to the Ouachita thrust front in the Fort Worth Basin (e.g., Pollastro et al, 2007), embrittlement and hydrocarbon generation during maximum burial have resulted in secondary porosity development (Lash and Engelder, 2009;Becker et al, 2010;Fall et al, 2012). This can prove favorable for hydraulic fracture stimulation campaigns and consequently enhances production rates Gale et al, 2010).…”

“…Although most previous studies have focused on the impact of exhumation on conventional petroleum systems, some of the most prospective shale gas and tight gas plays in the United States clearly have also been subject to major exhumation. These include the Mississippian Barnett Shale in the Fort Worth Basin (exhumation, >1500 m [∼4920 ft]; Jarvie et al, 2005Jarvie et al, , 2007Montgomery et al, 2005;Ewing, 2006), the Upper Cretaceous Mesaverde Group in the southern Piceance Basin (∼1800 m [∼5905 ft]; Nuccio and Roberts, 2003;Fall et al, 2012), and Pennsylvanian and older plays in the central Appalachian Basin (∼4400 m [∼14435 ft]; Reed et al, 2005). Deeper burial and subsequent exhumation in these basins have brought thermally mature, embrittled shales with substantial secondary porosities and higher hydraulic fracture stimulation potential closer to the surface (Bowker, 2003;Jarvie et al, 2007;Gale et al, 2010).…”