Abstract This study addresses the stratigraphic architecture and connectivity of fluvial sandstones of the Williams Fork Formation through outcrop analysis, and static and dynamic modelling of equivalent reservoirs in the Piceance Basin, Colorado. The Williams Fork Formation is a succession of fluvial channel sandstones, crevasse splays, floodplain mudstones and paludal coals that were deposited by meandering- and braided-river systems within coastal- and alluvial-plain settings. Three-dimensional (3D) static and dynamic reservoir models that are constrained to both outcrop-derived and subsurface data show how static connectivity is sensitive to sandstone-body type and width, and varies with net to gross ratio. Connectivity analyses of 3D outcrop-based architectural-element models show how relatively wide sandstone bodies enhance connectivity. At Mamm Creek Field, connectivity of sandstones that are pay within the middle Williams Fork Formation is 12–18% higher than for the lower Williams Fork Formation. For highly constrained 3D object-based models of architectural elements, connectivity is only 4% higher when crevasse splays are included as reservoir-quality sandstones. Dynamic simulation results also suggest that the best history match is possible by considering only point bars and channel bars (reservoir-quality sandstones) as pay. Additional research is necessary to determine the impact of crevasse splays on reservoir connectivity.

Abstract We propose a simple method to estimate facies probabilities based on statistical analysis of multidimensional crossplots of seismic attributes. Log scale facies flags related to thick sand bodies are created using petrophysics and rock physics analyses. These flags are then used to color crossplots of seismic scale attributes derived from AVO inversion of PP data (V P , V S , and density) and inversion of poststack fast and slow PS components of a 3C-3D survey. We show that by using these five seismic attributes and facies flags (like a colored five-dimensional crossplot), we can estimate the probability of thick sand bodies much better than when we crossplot two attributes at a time. Unlike commonly used approaches to map facies or lithologies from seismic data based on selecting regions in seismic attribute crossplots, our approach accounts properly for overlap among different facies and quantifies the probability of their occurrence.

Abstract Aggressive development of the Mesaverde gas accumulation in the Piceance Basin over the past decade has demonstrated that a commercial gas resource is present in much of the deeper part of the basin. Unlike tight gas resources in some other basins ( e.g. , the greater Green River Basin), commercial production doesn’t appear to be limited to specific fairways or sweet spots. There appears to have been a sufficient gas source within in situ coals and underlying marine shales to pervasively gas charge up to 3500 ft of the Mesaverde. An extensive vertical fracture system has resulted from over pressuring from hydrocarbon generation. Laramide tectonic fractures are also locally abundant. This fracture system has enabled vertical gas migration within an otherwise very low permeability system. In spite of being one of the oldest areas of tight gas production in the Rocky Mountain region, innovations in drilling and completion technology continue to expand the area of commercial production. Directional drilling has allowed over 20 bottom-hole locations to be accessed from a single surface location, and laterals reach up to 5000 ft. Microseismic imaging of hydraulic fracture stimulation has helped place bottom-hole locations optimally with regard to highly elliptical drainage patterns. Large water volume hydraulic fracturing has dramatically improved estimated ultimate recoveries (EURs) of wells in some areas. Also, unconventional pay picking has added significant resources that were not previously developed.

Abstract Aregionally extensive basin-centered gas accumulation in the Mesaverde Group of the Piceance Basin is currently being actively developed. Daily production has increased from less than 200 MMCFGD in the year 2000 to more than 1 BCFD currently. Most gas production in the Piceance Basin is from discontinuous fluvial sandstones of the Williams Fork Formation of the Mesaverde Group. In some areas of the southern Piceance Basin, 10-ac (4-ha) well density has proven successful. Estimated ultimate recoveries (EURs) of typical wells in these areas range from 1 to 2 bcf per well, resulting in reserves of about 60–120 bcf per section (1 mi 2 ; 2.5 km 2 ). The depth limits to the commercial gas accumulation are poorly defined, but it is possible that much of the deeper part of the basin may have commercial gas reserves. Within the area of commercial gas production, most gas is produced from a continuously gas-saturated interval in the Williams Fork. Productive intervals can attain gross thicknesses of more than 3000 ft (900 m). The gas-saturated interval thins toward the basin margins, where the Williams Fork gas reserves become subeconomic. This tremendous gas resource exists because of several important geologic circumstances. Large volumes of gas were generated from thick Mesaverde coals as they achieved high thermal maturity. Migration of this gas was inhibited by the very low permeability and discontinuous nature of the Mesaverde sandstone reservoirs. The rate at which gas was generated and accumulated in the reservoirs outpaced the rate at which gas could escape, resulting in overpressure. Eventually, the pressure of the gas phase in the pore system exceeded the capillary pressure of the water-wet pores, and water was expelled from the pore system, resulting in the development of an overpressured, gas-saturated reservoir with little movable water. In addition, the overall distribution and pressure of the gas in the Williams Fork is probably the direct result of pore-pressure-assisted fracturing and subsequent migration through the resulting natural fracture system. The orientations of the fracture populations are predetermined by the orientation of tectonic stresses at the time that the fractures formed, but the distribution and intensity of fracturing are mostly influenced by the history and magnitude of overpressuring during gas charging. Fractures in the Mesaverde in the Piceance Basin are primarily opening-mode fractures (also called extension fractures or joints). Some of these fractures are found to have opened, then they have been cemented, and then they opened again. In some cases, this process occurred repeatedly. It is well known that open fractures are a significant factor in the movement of subsurface fluids. In-situ permeabilities of the Mesaverde from well flow testing are measured to be up to three orders of magnitude higher than the matrix permeabilities measured from core. Because most fractures in the Mesaverde of the Piceance Basin are extension fractures, our analysis emphasizes the impact of the magnitude of pore pressure on effective stress and strain boundary conditions and how these may control extension fracturing. We find that high pore pressure compresses and shrinks the individual sand grains uniformly in all directions (poroelastic effects). As pore pressure increases, the lateral normal stress decreases, until under some conditions of pore pressure, the rocks experience tensile effective stress and fracture. These conditions were common during maturation of the coal-bearing lower Williams Fork, where pressures were high enough to fracture most of the rock types. Some parts of this section remain highly overpressured to the present day. As pressures decrease upward, away from the coal-bearing section, only fracture-prone sandstone lithologies fractured, causing stratigraphy to be a more important factor in the upward and lateral migration of gas. This gas-migration process is dominant below the top of continuous gas saturation. Above the top of continuous gas saturation is a transition zone that contains both gas-and water-bearing sandstones. Gas-charged sandstones in the transition zone were probably sourced by migration along major fault and fracture zones. The sandstones in the transition zone commonly have better porosity and permeability than those in the continuously gas-saturated interval. Conventional trapping is probably active in many transition-zone gas sandstones. Significant erosion of overburden has occurred in the Piceance Basin after peak gas generation. Gas expansion during exhumation probably had a significant effect on gas saturations. Gas expansion is significant when the gas accumulation is tightly sealed, when the reservoir depth after exhumation is shallow (<6000 ft; <1800 m). Gas expansion in discontinuous sandstone reservoirs has the potential to displace water into surrounding shales, resulting in reservoirs with no apparent downdip water.