Abstract The Wamsutter arch is a poorly defined, low-order, positive structural element of southwestern Wyoming. The arch plunges eastward from the northeast bulge of the Rock Springs uplift toward the Rawlins uplift and Sierra Madre uplift, but does not definitely join either of these latter structural elements. The stronger south flank of the arch dips into the Washakie segment of the Green River basin. The north flank fades gradually into the Great Divide segment of the Green River basin. The stratigraphic section follows. Gas and oil have been found in the Mesaverde Group, mostly in sandstones in the Almond Formation. To a lesser extent production has been obtained from sandstones within the Lewis Shale near the Lewis-Lance transition zone, and from the Ericson Sandstone. There is also minor production indicated from sand lenses in the Hiawatha Member of the Wasatch. Table Rock anticline on the southeast flank of the arch is the only structure with demonstrable surface closure. Tertiary gas was discovered here in 1946, with deeper Lewis and Mesaverde discoveries in 1954. Discovery of major gas reserves at Desert Springs in 1958 triggered rapid expansion of exploratory and development drilling which continues to date. Major new field discoveries include Patrick Draw, Arch, Playa, and West Desert Springs. Productive areas have expanded across original federal unit boundaries and have overlapped and coalesced, causing problems in nomenclature. Except for Table Rock, all fields discovered to date are stratigraphic traps with minor structural complexities. The oil and gas is found in closed sandstone bodies formed as offshore bars in the shallow Lewis and Almond seas. The Wamsutter arch is a young upwarp (possibly Pliocene) superimposed across older Tertiary and Late Cretaceous structural trends. The older structural patterns are imperfectly known.

Abstract 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.

ABSTRACT One essential component of productive sweetspots in the Upper Almond marine bar sands, Green River Basin, Wyoming, is thought to be the connection to the underlying coals and sands of the coastal plain. Vertical natural extension fractures may provide this connection. In 1993 Amoco drilled and completed the first horizontal well to test the productivity of the natural fractures within the Upper Almond bar sand in Echo Springs Field. Formation Microimager and Formation MicroScanner (marks of Schlumberger), herein FMI and FMS, and oriented cores were obtained in a slanted pilot hole and from a horizontal wellbore to determine the spacing, orientation, and apertures of natural fractures within the bar sand and adjacent facies. The total fracture population strikes N50-70E, with dips near vertical. Closed fractures are cemented by barite and calcite, whereas quartz druse, kaolinite, barite, and patchy calcite line open fractures. Fracture location and orientation determined by FMI/FMS are consistent with data derived from the core analysis. Forty individual fractures were evaluated from imaging 1490 feet of pilot hole, and 217 fractures were evaluated in over 2030 feet of horizontal wellbore. Dual induction resistivities were used to calibrate Formation Microimages in the pilot and horizontal holes for fracture aperture measurements. 5267 individual segment aperture calculations were made from 248 fracture images, and 898 measurements were made from core thin sections impregnated at in situ conditions. The initial comparison of fracture widths between thin section scanning electron microscopy measurements and Formation Microimage calculations of mean aperture resulted in poor agreement. This lack of agreement was largely due to a difference in what was measured by the two methodologies, and in the fracture length explored by the two methods. The FMI/FMS methodology only resolves apertures in the open portion of the fractures, whereas SEM measurements can be made on open and on mineralized portions of fractures. Core measurements were made on lengths of 3 cm, whereas the imaged mean aperture is a single filtered value for fracture intersections with the wellbore that roughly averaged 80 to 100 cm. A utility that permits the documentation of fracture aperture for each individual fracture segment identified on the electrical images provides a more appropriate comparison of image-derived and thin section apertures. Good agreement between the two methods was found when FMI segment apertures were compared only to the open thin section S.E.M. aperture measurements. The use of this coupled imaging and petrographic approach provides new avenues for mapping and understanding fracture permeability distributions in naturally fractured reservoirs.