Geologic analysis of the Hartzog Draw Field pilot area indicates that reservoir behavior is predominantly controlled by the processes of deposition and the diagenetic history of the genetic facies composing the reservoir. Central-bar, bar-margin, and interbar facies of the Cretaceous Shannon Sandstone were deposited as an elongate shelf sand ridge in the Cretaceous seaway of northern Wyoming.
A typical vertical sequence in the Hartzog Draw Field coarsens upward and consists of rippled to bioturbated, very fine-grained interbar sandstone interlayered with trough cross-bedded and rippled medium- to fine-grained bar-margin sandstone and overlain by cross-bedded and rippled medium- to fine-grained central-bar sandstone. The bar-margin facies generally has a sharp basal contact and exhibits an upward trend from trough cross-beds to small-scale cross-bedding and ripples that grade into the central bar. Interfingering contacts of central bar with shalier bar-margin and interbar facies disrupt the vertical and horizontal reservoir continuity. The bar-margin facies is best developed on the steeply sloping eastern margin of the field and interfingers westward into thicker central-bar sandstone. Westward of the northwest-southeast axis, the interbar facies and shelf shales split the reservoir into three horizons, thus creating thinner and less laterally extensive sand lenses at the westward extent of the field.
Core samples were analyzed by thin-section petrography, SEM (scanning electron microscope), and XRD (X-ray diffraction) to assess primary and secondary controls on porosity. Shannon sands are feldspathic-litharenites (60% quartz, 15% feldspar, and 25% lithic rock fragments). Primary controls on porosity are sediment texture and the amount of labile grains (glauconite, chert, and rock fragments). Secondary properties that modify porosity include carbonate cementation, sedimentary structures, dissolution of carbonate cement, and occlusion of secondary porosity by compaction and formation of quartz and clay cements. Core plug permeabilities and porosities observed in thin sections for cross-bedded central-bar and bar-margin sandstone range from 1 to 40 md and 2.5% to 12%, respectively. Thinner-bedded and shalier bar-margin and interbar facies have permeabilities ranging from less than 1 md to 6 md and thin-section porosities from 0% to 2%. Lower porosity and permeability values are caused by a large increase in detrital clay content of these units.
Flow units represent portions of the reservoir that have similar fluid-flow properties. Integration of stratigraphic, sedimentologic, and petrophysical data into reservoir flow units improves predictions of trends in reservoir quality. Within the flow units, geologic features that greatly influence fluid flow are (1) stratification, (2) shale laminations, (3) cement, and (4) cross-bedding.
