ABSTRACT The Uinta Basin of eastern Utah is an intermontane basin that contains an ~2-km-thick succession of mostly carbonate-rich mudrock assigned to the Eocene Green River Formation. In the southwest part of the basin, along Nine Mile Canyon and its tributary canyons, the middle member of the Green River Formation contains numerous interbedded sand bodies. Previous researchers have interpreted these sand bodies variably as lacustrine deltaic mouth bars, terminal fluvial distributary bars, and various types of fluvial (delta plain/floodplain/braid plain) bar. Using some modern western U.S. lakes as partial analogues, and taking into account the overall lacustrine basin context of a widely fluctuating, wave-influenced, alkaline-lake shoreline, we again interpret many of the sand bodies to be fluvial in origin. Several sand bodies both truncate and are capped by brown to red-maroon and variegated weak to noncalcareous mudstone with root and desiccation structures, indicating terrestrial deposition well away from the lake shoreline. Others display steep cutbanks from which noncalcareous, inclined heterolithic stratification laterally accreted as fluvial side bars. Utilizing helicopter-based light detection and ranging (LiDAR) data, we investigated additional sand bodies that may be better examples of deltaic mouth bars. In contrast to the more commonly documented highstand progradational mouth bars of marine and open lake settings, these sand bodies are interpreted to have originated as late-lowstand or transgressive system tract fluvial channels that were then flooded and modified by waves following lake transgression. These examples illustrate that any large-scale sandy bed form present in the general vicinity of a closed basin’s fluctuating lake shore may be expected to have formed under more than one set of environmental conditions. A revised set of guidelines is therefore presented to aid in the interpretation of lacustrine deltaic mouth bars.

ABSTRACT Characterizing unconventional reservoirs involves the investigation of a wide range of potential source-rock targets at various stages of thermal maturity. These samples may contain a mixture of kerogen, bitumen, oil, and pyrobitumen within their fabric. Thus, it is critical that we properly identify and examine each organic phase to better understand reservoir properties. In the present study, we have selected samples of gilsonite from a naturally occurring solid hydrocarbon deposit to serve as an analog for characterizing the bitumen phase of generation. Gilsonite is an aromatic-asphaltic solid bitumen found in vertical veins along the eastern portion of the Uinta Basin, Utah. It is thought to be an early generation product from oil-prone Green River Shale source beds and is similar to low-maturity crude oil in composition. It has a high nitrogen content, low sulfur content, and high melting point (fusibility) and is soluble in organic solvents. We have used a variety of analytic methods to characterize this material, including standard optical organic petrology and scanning electron microscopic imaging to examine the occurrence of organic porosity. Optical organic petrology analyses using both air and oil immersion objectives show that the polished gilsonite surfaces are typically dark grey and featureless. Optical evidence for the presence of macerals and inorganic constituents is absent. Visual estimates suggest that fractures make up approximately 1% of the conchoidal fracture plane, whereas the pencillated variety contains approximately 2% fractures along with 5% shallow pits. Scanning electron microscopic images also show the occurrence of fractures within gilsonite, but the matrix contains no evident organic porosity. The results of our analyses suggest that, unlike pyrobitumen, pre-oil solid bitumen represented by gilsonite was found to contain no significant occurrences of organic nanoporosity within its matrix. Gilsonite does have minor pitting and fractures, but these do not represent an effective interconnected pore network and are probably artifacts of weathering/sampling. Thus, this material would not represent a potential candidate for in-situ petroleum storage capacity. Whether this is typical of all naturally occurring solid bitumen is debatable, considering that gilsonite has undergone some secondary alteration via devolatilization and limited biodegradation. Nevertheless, the pore-scale imaging of this solid bitumen provides potentially important new insights for unconventional reservoir characterization.

Abstract Reservoir rocks can be highly sensitive to fluids introduced through hydraulic fracturing, water disposal, or waterflood injection. The sensitivity of reservoir rocks to fluids can lead to reduced permeability and permanent formation damage resulting in reduced productivity or injectivity. It is generally assumed that clays are the primary culprit in formation damage caused by swelling, increased clay-bound water, water shock, or denigration. In this chapter, we present results from a two-year effort to understand the fluid sensitivity of tight sandstone reservoirs in the Greater Monument Butte Unit (GMBU) in the Uinta Basin, Utah, U.S.A. Newfield Exploration (NFX) drills and completes approximately 200 wells per year in the field, which is currently under waterflood with injection rates of ~90,000 barrels per day. When we initiated this study, NFX completed wells with fresh water. Pore-scale imaging was the key to designing new core flood experiments that led to optimized completions fluids for the field. Initially, we assumed that potential fluid sensitivity was caused by mixed-layer illite-smectite (I/S). XRD (x-ray diffraction) and SEM (scanning electron microscope) images indicated that some GMBU reservoir rocks contained pore-bridging I/S. We designed initial core flood experiments combined with core nuclear magnetic resonance to identify and quantify clay reactions. The results of these initial tests indicated that the reservoirs were sensitive to lower-salinity completions fluids and a reduction in permeability was observed. We utilized a new approach involving pore-scale imaging to identify the mechanism causing permeability reduction. Comparison of SEM images of minerals in pores before and after fluid placement identified calcite dissolution and fines migration as the cause of permeability reduction. Micro-CT (micro-computed tomography) scans combined with registered EDX (energy-dispersive x-ray spectroscopy) mineralogy provided the context for the severity of the problem, especially in the better reservoir rock. The results of this work challenge a number of commonly held assumptions of rock–fluid sensitivity and have implications on how to design effective fluid sensitivity studies using core. This work involved collaboration between petrophysicists, geologists, engineers, and facilities personnel to design and implement a completions fluid that does not damage multiple reservoirs while remaining cost effective and efficient. This work demonstrates the value of focused science within the context of cost and field operational constraints.