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Non-marine carbonates at Lakeside (Utah) are the depositional record of transitional shoreline palaeoenvironments around 1,285 m, as lake elevation fell from Lake Bonneville levels to low-stand Great Salt Lake levels of 1,284-1,278 m. Lakeside carbonates provide a rare example of onshore groundwater spring deposits connected to lacustrine microbialite reefs. Clotted fabrics and mineralized bacteriomorphs suggest microbial influence both in groundwater spring and littoral carbonates.Thrombolitic clotted aragonite and dendritic clotted intermediate magnesium calcite may document two distinct microbial ecosystems each with a specific mineralogy.Radiocarbon dates from interior to outer layers of a 20 cm littoral microbialite suggest several thousand years of domal growth. Climate fluctuations may be recorded in littoral deposits by the alternation of ooids (increased salinity, arid conditions) with ostracods (fresher water, humid conditions). Successive higher frequency cycles of sedimentation, exposure, microkarst and early diagenesis were cemented by vadose and phreatic very high magnesium calcite and non-stoichiometric dolomite.Several layers of littoral and beach deposits accumulated during longer lacustrine transgressive-regressive cycles. Clastic detritus and lack of known initial U and Th concentrations could explain the lack of correlation between widely scattered U-Th ages and closely grouped 14 C dates. Calibrated ages from radiocarbon dating may have been increased by long residence time of groundwater in bedrock, since 87 Sr/ 86 Sr signatures do indicate possible littoral-zone mixing of lake water with groundwater from outcropping and subsurface Mississippian Great Blue Limestone.The perplexing Lakeside carbonate system is the result of interaction between microbial and chemical processes during sedimentation and early diagenesis.

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Over 240 horizontal wells with highly variable production results have been drilled in the Uteland Butte member (UBm) of the lower Green River Formation in the Uinta Basin, Utah. The best wells have each produced more than 300,000 barrels of oil in the first 12 months of production, with conservative Estimated Ultimate Recoveries (EURs) for several wells above a million barrels. Conversely, the poorest UBm wells have initial production rates of less than 10,000 barrels of oil in the first year and will never recoup their drilling costs. Pore pressure, oil viscosity, well length, and well completion are recognized as important controls on well productivity. Less understood, but of equal importance, is the variability in reservoir types across the UBm play. The UBm can be divided into sub-plays by district using the dominant pore systems in each area. We defined four distinct sub-plays within the Uinta Basin: 1) intergranular-dominated porosity, 2) intercrystalline- pore-dominated dolomite, 3) mixed intercrystalline-organic porosity, and 4) organic porosity. Reservoirs in the intergranular-dominated porosity sub-play are mostly present in the form of nearshore siliciclastic and carbonate bars, such as ooid and ostracod shoals, fluvial mouth bars, and nearshore siliciclastic bars. The normal pressure and charge in these reservoirs are due to hydrocarbon migration out of the deeper basin. Source rocks in this sub-play have an average maturity of 0.5 to 0.7 vitrinite reflectance (VRo), too low for mainstage oil generation for these lacustrine shales (Ruble and others, 2001), and produce highly viscous black wax with very low gas-to-oil ratios (GORs). To date, horizontal wells drilled in this sub-play have not been economically successful. The intercrystalline-pore-dominated sub-play consists of thin (<2 to 8+ feet), laterally continuous, high-porosity dolomites that act as the best reservoirs. The reservoir is normally to slightly overpressured and is predominately charged with hydrocarbons that migrated out of the deeper basin. This sub-play was the first to be drilled horizontally, with the dolomite beds being identified as the highest quality targets. The UBm is thick in the intercrystalline-pore-dominated fairway, consisting of over 130 feet of carbonates and black shales, with only a fraction of the interval being high-porosity dolomites. This sub-play has an average VRo of 0.6 to 0.8, still too low for mainstage oil generation in these rocks and produces a migrated black wax with low GORs. The mixed intercrystalline-organic porosity sub-play is largely self-sourced and significantly overpressured. This sub-play has the thickest gross section and is dominated by thin dolomite beds, thicker argillaceous limestones, and thicker shaley beds, with the latter units contributing significant production. Maturities in this sub-play range from 0.8 to 1.0 VRo. This sub-play produces a yellow to gray wax with moderate GORs. Finally, the organic-porosity-dominated sub-play is highly overpressured and completely self-sourced. There is relatively little reservoir-quality dolomite, the limestones are more argillaceous, and the organic-rich carbonate shales are thicker. The productive reservoir in this sub-play consists of organic porosity largely contained in bitumen that has been expelled at lower maturity, then continued to thermally degrade with higher maturity, converting to zones of interconnected organic porosity. Maturities range from 1.0 to 1.2 VRo and the hydrocarbons produced are a bright yellow wax with relatively high GORs. To be economically developed, each of these sub-plays requires individually tailored drilling, completion, and production strategies. By recognizing the important differences these pore systems exert on best development practices and then accurately mapping them across the basin, operators, interest owners, and regulatory agencies can more efficiently plan operations.

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