Thesis (Ph. D.)--University of Texas at Dallas, 2006. / Includes vita. Includes bibliographical references (leaves 128-141)

Fractures can increase the permeability and producability of reservoirs by acting as fluid and gas conduits to wells. Networks of fractures are most important in reservoirs where little to no matrix permeability exists such as tight gas sandstones. Two significant variables, fracture length and the abundance of fractures, are not readily measurable from subsurface observations such as those obtained from cores or well logs. Numerical models suggest natural fracture apertures and lengths follow systematic power-law (Marrett, 1996; Olson, 2007) and negative exponential distributions (Olson, 2004); fracture trace lengths are interrogated. This study tests those propositions through study of fractures in outcrop. Outcrops of the Cretaceous Frontier Formation at Oyster Ridge in southwest Wyoming and Oil Mountain near Casper, in central Wyoming provide evidence of reservoir scale fracture networks in sandstones. In the subsurface the Frontier Formation sandstones are reservoirs that produce gas and oil in several Wyoming basins. I mapped fracture patterns at twenty locations at Oyster Ridge and Oil Mountain and measured fracture trace length distributions and abundance (intensity). Fracture cumulative length distribution plots illustrate systematic length distributions. Trace length distributions of every fracture network follow negative exponential distributions regardless of the number of fractures (N = 39 to N = 394) or the size of the outcrop (1.3 to 710 m²). Results show that the fractures follow a negative exponential distribution over a range of lengths of a few centimeters to tens of meters. These trace length distributions are consistent with geomechanical model fracture pattern simulation results by Olson (2004) that suggests negative exponential trace length distribution result from fracture to fracture interaction during fracture formation. Length distributions from my field study are inconsistent with pattern simulation results by Marrett (1996) and Olson (2007) and others that produce power-law length distributions. This inconsistency suggests that the model assumptions of Olson (2004) best account for the patterns I observed. Two dimensional fracture intensity, defined as the total fracture trace length divided by the map area, was measured for each outcrop to determine how structural position affects fracture abundance patterns. Two-dimensional fracture intensity measurements collected at thirteen structural locations around Oil Mountain show higher values of fracture intensity near the fold-axial-trace compared to fold limbs. The difference is as much as 7.4 fractures per meter near fold hinges compared to 0.63 fractures per meter in fold limbs. Outcrops near small faults, with displacement of a few meters, show an increase in fracture intensity from background values around 4.8 fractures per meter to values nearly three times as high (13 fractures per meter) near faults. Values of fracture intensity that are more elevated near small tear faults imply that faulting has a greater influence on fracture intensity than folding. / text

The Frontier Formation in the Green River Basin of southwestern Wyoming consists of Late Cretaceous (Cenomanian-Turonian) marine and non-marine sandstones, siltstones, mudstones and coals deposited on the western margin of the Cretaceous Interior Seaway. Tight gas reservoirs exist in subsurface fluviodeltaic sandstones in the upper Frontier Formation (Dry Hollow Member) on the north-south trending Moxa Arch within the basin. These strata crop out in hogback ridges of the Utah-Idaho-Wyoming Thrust Belt approximately 40 km west of the crest of the Moxa Arch. Detailed, quantitative outcrop descriptions were constructed using emerging photogrammetric techniques along with field observations and measured sections at five key outcrop localities along the thrust belt. Understanding the architectural style of this low net-to-gross fluvial system allows for improved reservoir prediction in this and other comparable basins. The architectural style of the Dry Hollow Member fluvial deposits varies vertically as the result of a relative shoreline transgression during Dry Hollow deposition. Amalgamated conglomerates and associated fine to coarse sandstones near the base of the section and much thinner, isolated sandstones near the top of the Dry Hollow occur in laterally extensive units that can be identified over tens of kilometers. These units also provide means to relate outcrop and subsurface stratigraphic architecture. Combined with available subsurface data, fully-realized 3D static reservoir models for use as analogs in subsurface reservoir characterization may be constructed. Grain size, reservoir thickness and connectivity of fluvial sandstones is generally greatest near the base of this member and decreases upward overall. Despite relative isolation of some channel bodies, geocellular facies modeling indicates good lateral and vertical connectivity of most channel sandstones. The Kemmerer Coal Zone, with little sandstone, divides lower and upper well-connected sandy units.