Multiscale Heterogeneity Characterization of Tidal Channel, Tidal Delta, and Foreshore Facies, Almond Formation Outcrops, Rock Springs Uplift, Wyoming
Richard A. Schatzinger, Liviu Tomutsa, 1999. "Multiscale Heterogeneity Characterization of Tidal Channel, Tidal Delta, and Foreshore Facies, Almond Formation Outcrops, Rock Springs Uplift, Wyoming", Reservoir Characterization—Recent Advances, Richard A. Schatzinger, John F. Jordan
Download citation file:
In order to accurately predict fluid flow within a reservoir, variability in the rock properties at all scales pertinent to the specific depositional environment needs to be taken into account. The present work describes rock variability at scales from hundreds of meters (facies level) to millimeters (laminae) based on outcrop studies of the Upper Cretaceous Almond Formation. Tidal channel, tidal delta, and foreshore facies were sampled on the eastern flank of the Rock Springs uplift, southeast of Rock Springs, Wyoming. The Almond Formation was deposited as part of a mesotidal Upper Cretaceous transgressive systems tract within the greater Green River Basin.
Bedding style, lithology, lateral extent of beds of bedsets, bed thickness, amount and distribution of depositional clay matrix, bioturbation, and grain sorting provide controls on sandstone properties that may vary more than an order of magnitude within and between depositional facies in outcrops of the Almond Formation. Permeability along these surfaces is often decreased by cementation, smaller pores, tighter grain packing, and compaction of sand-size rock fragments. These features can be mapped on the scale of an outcrop. Application of outcrop heterogeneity models to the subsurface is generally hindered by differences in diagenesis between the outcrop and the reservoir, poorly defined interwell subsurface continuity and facies architecture, and different absolute values of petrophysical properties (which often includes scaling problems) between the outcrop and the reservoir. In this paper we emphasize linkage between lateral cyclicity of petrophysical properties and the scale of primary bedding features. Such relationships can be transferred from outcrops directly into the subsurface because scaling problems are avoided.
The measurements for this study were performed both on drilled outcrop plugs and on blocks. One-inch-diameter plugs were taken at lateral spacing from 15 cm (6 in.) to 16.5 m (50 ft) and vertical spacing from 8 cm (3 in.) to 1.5 m (5 ft) to capture hierarchically stacked patterns of variations on the scale of meters to hundreds of meters. Probe permeameter permeability and x-ray computed tomography (CT) porosity from outcrop blocks captured variations at the scale of a few mm to a few hundred mm. Conventional gas porosity and permeability measurements were performed on the plugs and were integral to mapping the distribution of petrophysical properties at the scale of the facies (tens to hundreds of meters). Microscopic-scale heterogeneities such as grain size, pore distribution, authigenic cement content, and paragenetic stages were recorded using thin-section point-count methods and semi-automated petrographic image analysis.
In this study we found that permeability decreased 50-60% across bedding surfaces, by about 50% across bedset boundaries, and by 1-2 orders of magnitude across sandstone facies contacts. Permeability distribution tends to map parallel the “grain” of bedding within bedsets. Mapping also indicates that bedset boundaries are essentially always inclined to upper and lower facies boundaries. Fluid flow through facies must cross bedset boundaries. Lateral cyclicity of permeability is primarily related to bedding surfaces and the periodicity of individual sandwaves within major bedsets. The frequency of bedset boundaries encountered can then be a significant controlling factor to fluid flow and recovery efficiency.
CT and minipermeameter analysis map petrophysical properties at a scale approximately two orders of magnitude finer than that mapped using plugs. In our study, large-scale plug data and the detailed minipermeameter maps of sandstone blocks indicate similar ranges of permeability for similar facies. Therefore, when the architecture of depositional facies within this system is correctly described, data from small-sized samples are acceptable for modeling the reservoir at a larger scale.
Figures & Tables
Reservoir Characterization—Recent Advances
Optimum reservoir recovery and profitability result from guidance by an effective reservoir management plan. Success in developing the most appropriate reservoir management plan requires knowledge and consideration of (1) the reservoir system, including rocks, fluids, and rock-fluid interactions, as well as wellbores and associated equipment and surface facilities; (2) the technologies available to describe, analyze, and exploit the reservoir; and (3) the business environment under which the plan will be developed and implemented. Reservoir management plans de-optimize with time as technology and the business environment change or as new reservoir information becomes available. Reservoir characterization is the process of creating an interdisciplinary high-resolution geoscience model that incorporates, integrates, and reconciles various types of geological and engineering information from pore to basin scale. The reservoir data are then conceptually and quantitatively modeled and compared to the historical production data and fluid flow distribution patterns within and beyond the limits of the reservoir to match well production histories and predict their behavior. The goals of reservoir characterization are to simultaneously (1) maintain high displacement efficiency, (2) optimize high sweep efficiency, (3) provide reliable reservoir performance predictions, and (4) reduce risk and maximize profits. Notice that in addition to the technical concepts that we normally associate with "characterization," maximizing profits is an essential element of this process. Papers from the Fourth International Reservoir Characterization Technical Conference (1997), sponsored by the U.S. Department of Energy, this publication is a unique compilation of 27 papers covering every aspect of reservoir characterization and has been a popular AAPG publication since that time. Using an interdisciplinary approach, the papers address qualitative information as well as integrated quantified data and culminate in a fully integrated study.