Petroleum reservoir

About: Petroleum reservoir is a research topic. Over the lifetime, 5403 publications have been published within this topic receiving 83535 citations. The topic is also known as: petroleum deposit.

High-Porosity Cenozoic Carbonate Rocks of South Florida: Progressive Loss of Porosity with Depth

Abstract: Porosity measurements by borehole gravity meter in subsurface Cenozoic carbonates of south Florida reveal an extremely porous mass of limestone and dolomite which is transitional in total pore volume between typical porosity values for modern carbonate sediments and ancient carbonate rocks. A persistent decrease of porosity with depth, similar to that of chalks of the Gulf Coast, occurs in these rocks. We make no attempt to differentiate depositional or diagenetic facies which produce scatter in the porosity-depth relationship; the dominant data trends thus are functions of carbonate rocks in general rather than of particular carbonate facies. Carbonate strata with less than 20% porosity are absent from the rocks studied here. Aquifers and aquicludes cannot be distinguished on the basis of porosity. Although aquifers are characterized by great permeability and well-developed vuggy and even cavernous porosity in some intervals, they are not exceptionally porous when compared to other Tertiary carbonate rocks in south Florida. Permeability in these strata is governed more by the spacial distribution of pore space and matrix than by the total volume of porosity present. Dolomite is as porous as, or slightly less porous than, limestones in these rocks. This observation places limits on any model proposed for dolomitization and suggests that dolomitization does not take place by a simple ion-for-ion replacement of magnesium for calcium. Dolomitization may be selective for less porous limestone, or it may involve the incorporation of significant amounts of carbonate as well as magnesium into the rock. The great volume of pore space in these rocks serves to highlight the inefficiency of early diagenesis in reducing carbonate porosity and to emphasize the importance of later porosity reduction which occurs during the burial or late near-surface history of limestones and dolomites.

Cementation Exponents in Middle Eastern Carbonate Reservoirs

Abstract: The cementation exponent, m, is a major factor of uncertainty in the calculation of hydrocarbon/water saturation in heterogeneous carbonate reservoirs. Hydrocarbon saturations as high as 70 or 80% calculated with the conventional value m=2, may disappear completely with m values of 3 and 4, which are quite common in carbonate rocks. Laboratory data obtained in heterogeneous carbonate reservoirs often show a wide scatter. Constant (average) m values are usually used in spite of such scatter, and data points with m values much higher than the average value are often rejected to obtain straight-line trends. This paper presents the results of a study of the relationship between variable m values measured on core plugs and detailed carbonate rock types. The scatter in the data is analyzed in terms of rock type. The authors conclude that the high m values are often representative for specific rock types and that these values should not be rejected but applied selectively in log analysis over those intervals where these rock types occur.

Quantitative Outcrop Data for Flow Simulation

Abstract: An architectural analysis documents variations in bedding geometry and rock properties within a tide-influenced deltaic sandstone exposed in the Cretaceous Frontier Formation of central Wyoming, USA. Digital maps of bedding, lithofacies, and diagenetic cements, as well as vertical logs of grain size, lithofacies, and permeability, describe rock properties that potentially influence fluid flow behavior. These records are used to construct simulation models that assess the relative importance of different types of geologic variability on prediction of subsurface fluid flow. Two 25-meter-thick tide-influenced deltaic sandstone bodies coarsen upward and contain inclined beds that reflect episodic delta-front progradation. Decimeters- to meters-thick beds within bodies alternate between cross-stratified sandstones formed during rapid flows and shales deposited during more quiescent conditions. Down depositional dip, bed-draping shales are more continuous and lithofacies within sandstone beds become finer-grained and increasingly heterolithic. As sandstone beds fine down dip, mean permeability values decrease and coefficients of variation increase, permeability values change from nearly normal distributions to highly right-skewed, and permeability values become more strongly spatially correlated. Nodular cements also affect permeability. All of these variations were modeled using stratigraphic cornerpoint grids that preserve stratal geometry and gridblocks with properties assigned using a combination of rock property maps and statistical models based on rock property logs. Simulations predict effects on fluid flow of geologic heterogeneity at different scales, the influences of process variables, and the effects of different methods of grid construction and rock property assignment. Flow simulations of water flooding through a 22 m thick by 360 m long segment of a deltaic sandstone oil reservoir predict that: (1) rapid flow through coarser-grained deposits at the top of the sandstone body tends to draw water upward; (2) thin shales draping sandstone beds shunt downdip-directed flow downward and updip-directed flow upward; (3) cement nodules cause more tortuous flow patterns but have little effect on recovery efficiency; (4) Methods of predicting intrafacies correlation of permeability have little effect on flow behavior at this scale. A simulation model constructed using a high-resolution Cartesian grid did not resolve the effects of inclined shales, demonstrating the usefulness of stratigraphic cornerpoint grids for modeling flow through complex geologic deposits. Flow simulations of tracer flow through a meter-thick cross-stratified bed within the deltaic sandstone body showed that at this scale shale drapes and models of the intrafacies distribution of permeability have statistically significant effects.

Sulfuric acid speleogenesis of Carlsbad Cavern and its relationship to hydrocarbons, Delaware Basin, New Mexico and Texas

Abstract: Sulfur-isotope data and pH-dependence of the mineral endellite support the hypothesis that Carlsbad Cavern and other caves in the Guadalupe Mountains were dissolved primarily by sulfuric acid rather than by carbonic acid. Floor gypsum deposits up to 10 m thick and native sulfur in the caves are significantly enriched in {32}S; (isotope){34}S values as low as -25.8 per mil (CDT) indicate that the cave sulfur and gypsum are the end products of microbial reactions associated with hydrocarbons. A model for a genetic connection between hydrocarbons in the basin and caves in the Guadalupe Mountains is proposed. As the Guadalupe Mountains were uplifted during the late Pliocene-Pleistocene, oil and gas moved updip in the basin. The gas reacted with sulfate anions derived from dissolution of the Castile anhydrite to form H[2]S, CO[2], and "castile" limestone. The hydrogen sulfide rose into the Capitan reef along joints, forereef carbonate beds, or Bell Canyon siliciclastic beds and there reacted with oxygenated groundwater to form sulfuric acid and Carlsbad Cavern. A sulfuric-acid mode of dissolution may be responsible for large-scale porosity of some Delaware basin reservoirs and for oil-field karst reservoirs in other petroleum basins of the world.

Late Devonian and Early Mississippian Bakken and Exshaw Black Shale Source Rocks, Western Canada Sedimentary Basin: A Sequence Stratigraphic Interpretation

Abstract: The Late Devonian and Early Mississippian Bakken and Exshaw formations are a continuum of regionally correlated, organic-rich (up to 35% total organic carbon), black shale source rocks covering much of the Western Canada sedimentary basin. The Bakken Formation is composed of (1) a black mudstone lower member, (2) a gray mudstone/sandstone middle member, and (3) a black mudstone upper member. The Exshaw Formation, beneath the Alberta Plains and in exposures in the Foothills and Front Ranges of the Rocky Mountains, is composed of (1) a lower black shale member and (2) an upper siltstone member. The basal black shale unit of the Lower Mississippian Banff Formation, overlying the Exshaw Formation, is a second organic-rich interval. These black shales are regionally significant hydrocarbon source rocks and local reservoirs. The middle Bakken member is a locally important reservoir rock with substantial economic potential. The Bakken and Exshaw formations and the basal Banff black shale are divisible into three systems tracts: (1) a transgressive systems tract, (2) a lowstand systems tract, and (3) a second transgressive systems tract. Lodgepole and Banff formation carbonates, overlying the Bakken and Exshaw formations, are part of a highstand systems tract. A sequence boundary occurs between the lower and middle Bakken members. The conformable equivalent of this sequence boundary is within the Exshaw black shale member. Variations in the internal composition of these systems tracts imply that two depocenters, (1) the Williston basin and (2) the Prophet trough and the western margin of the North American craton, were affected differently by relative sea level rise and fall during Bakken and Exshaw deposition because of differences in water depth and sediment accommodation. Spatial and temporal changes in black shale and gray mudstone/sandstone, as highlighted by this sequence stratigraphic interpretation, may have significant impacts on source rock potential and hydrocarbon reservoir size, location, and quality.