Abstract Autogenic fluvial dynamics, including river avulsion, influence the distribution of channel sand bodies in alluvial deposits. Over long timescales, autogenically organized avulsions can generate stratigraphic patterns such as clusters of sand bodies when avulsions preferentially return to previous channel locations, or evenly spaced sand bodies when avulsions preferentially fill topographic lows. Consequently, quantifying stratigraphic patterns may provide an avenue for reconstructing paleoavulsion dynamics from ancient deposits. Several quantitative approaches have been used to quantify the degree to which channel-belt deposits are distributed randomly, evenly, or with clustered patterns; however, to date, there are only a few examples where these metrics have been applied in outcrop studies. Here we present a quantitative analysis of stratigraphic architecture in the lower Williams Fork Formation (Cretaceous, Colorado) to quantify the paleoavulsion pattern in this interval. A spatial-point-process statistic (the K function) and the compensation statistic are applied to stratigraphic data mapped from a terrestrial lidar digital outcrop model. Both analyses show random channel-body distributions and random basin filling at short (less than 200 m) spatiotemporal scales, which suggests that lower Williams Fork channels avulsed randomly. To evaluate the sensitivity of the K function to different degrees of stratigraphic organization, we use a two-dimensional (2D) geometric model to build synthetic stratigraphy with different degrees of sand-body clustering. Model results show that the lower Williams Fork data set should be of sufficient size and resolution to detect strong clustering signals, if they were present. This type of sensitivity analysis is helpful for comparing results of spatial-point-process analyses among outcrop examples with confidence. The random paleoavulsion pattern inferred from lower Williams Fork stratigraphy in this locality contrasts with previously published analyses that show qualitative clustering at larger scales; however, these results are not incompatible if avulsions remained clustered regionally over long timescales.

Abstract Study of a regional three-dimensional seismic data set by Cumella and Ostby (2003) indicated the potential existence of wrench faults in the southern Piceance Basin, Colorado. Although the faults could be inferred to cut through the productive interval, no direct observation was possible until the Reservoir Characterization Project (RCP) conducted a multicomponent seismic study at Rulison Field. This study confirms the existence of faults and coduments their importance in creating fracture zones critical to higher expected ultimate recovery (EUR) well production within the field. Three-dimensional seismic data were acquired at Rulison Field by RCP to investigate whether zones of high fracture density within the Mesaverde reservoir interval could be detected. Three time-lapse, multicomponent seismic surveys were acquired in 2003, 2004, and 2006. The study confirmed the existence of wrench faults, documented zones of high fracture density, and observed pressure depletion within these zones. Wrench faults and fracture zones play an important role in the creation of “sweet spots” associated with wells of high EUR. Sweet spot identification with multicomponent seismic data can improve the economics of tight gas exploration and production.

Abstract The objectives of this study are to characterize the distribution and production of gas and water within the Mesaverde basin-centered gas play in the Piceance Basin and to determine the extent by which they are affected by variations in hydrocarbon charge and basin hydrodynamics. Several approaches have been taken in this study to understand the distribution of fluids within the Mesaverde Group. They include (1) modeling gas generation within the Piceance Basin, (2) mapping the gross gas column based on mud-log shows, (3) mapping the distribution of wells with high water production, and (4) identifying reservoir zones with high water production. This work has been integrated with the regional stratigraphic framework and fracture distribution to understand their influence on the movement of fluids within the basin. The results of these studies indicate that the distribution of gas within the Mesaverde Group reflects both total gas yield and the ability of different sandstone bodies within the Mesaverde to transmit and/or trap and retain gas. Basin modeling indicates that coals within the Iles Formation and the lower part of the Williams Fork Formation have generated the largest volume of gas. Organic-rich continental shales, although thick and present throughout the Mesaverde Group, generally have low hydrogen indices and have generated comparatively small volumes of gas. Marine shales at the base of the section have slightly higher hydrogen indices than continental shales within the Mesaverde Group, but have moderately low total organic carbon and have also generated smaller volumes of gas than the coals. Basin modeling indicates that gas generation was greatest in or near the deep axis of the basin in the north and reflects greater thermal maturity of source beds. A fairly consistent relation exists between the volume of gas generated from Mesaverde source rocks and the height of the gas column within the Mesaverde, suggesting that the distribution of gas within the basin is, at least in part, controlled by gas charge. The Mesaverde gas column is thickest along the northern half of the basin axis and decreases to the flanks, consistent with variations in total gas generation. Produced water also varies relative to the top of the mapped gas. The very low permeability of Mesaverde reservoirs indicates that long-distance migration of fluids (gas and water) is largely controlled by fractures. Natural fractures in the Piceance Basin are strongly parallel; hence, connectivity depends mainly on fracture density, length, and height. Most fractures terminate at sandstone body margins; hence, discontinuous fluvial-channel sandstones within distal braided-stream and meandering-stream facies are characterized by lower fracture connectivity than more continuous marine sandstones and amalgamated proximal braided-stream sandstones. This, combined with their very low permeability, results in low fluid mobility. These sandstones are less likely to leak gas to the surface or to act as recharge conduits for surface water. Hence, gas is preferentially trapped in poorly amalgamated distal braided-stream and meandering-stream fluvial channels, whereas the more continuous marine sands and amalgamated proximal braided-stream sandstones are conduits for migration of gas out of the basin and recharge of water into the subsurface.