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Petroleum reservoirs may contain any of the three fluid phases--water (brine), oil, or gas. The initial distribution of phases depends on depth, temperature, pressure, composition, historical migration, type of geological trap, and reservoir heterogeneity (that is, varying rock properties). The forces that originally distribute the fluids are gravity, capillary, molecular diffusion, thermal convection, and pressure gradients. It is generally assumed that reservoir fluids are in a static state when discovered or, more correctly, that fluids are moving at a very slow rate relative to the time required to extract the fluids (10 to 50 years). Clearly the fluids may still be in a dynamic state in terms of geological time.
- Geology > Geological Subdiscipline (0.69)
- Geology > Mineral (0.47)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N2), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life.
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Real reservoir fluids contain many more than two, three, or four components; therefore, phase-composition data can no longer be represented with two, three or four coordinates. Instead,phase diagrams that give more limited information are used. Figure 1 shows a pressure-temperature phase diagram for a multicomponent mixture; it gives the region of temperatures and pressures at which the mixture forms two phases. The analog ofFigure 1 for a binary system can be obtained by taking a slice at constant mole fraction of Component 1 through the diagram inFigure 1. Also given are contours of liquid-volume fractions, which indicate the fraction of total sample volume occupied by the liquid phase; however,Figure 1 does not give any compositional information.
- North America > United States > Texas (0.30)
- North America > United States > California (0.30)
- North America > United States > Texas > Permian Basin > Val Verde Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Val Verde Basin (0.99)
- North America > United States > Wyoming > Tensleep Formation (0.98)
- North America > United States > Gulf of Mexico > Ellenburger Formation (0.98)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Information Technology > Knowledge Management (0.41)
- Information Technology > Communications > Collaboration (0.41)
Design for preventing or minimizing the effects of accidents is termed accidental limit states (ALS) design and is characterized by preventing/minimizing loss of life, environmental damage, and loss of the structure. Collision, grounding, dropped objects, explosion, and fire are traditional accident categories.
- South America > Brazil (1.00)
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- North America > Canada (1.00)
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- Summary/Review (1.00)
- Research Report > New Finding (1.00)
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- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.67)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.67)
- Transportation > Marine (1.00)
- Transportation > Infrastructure & Services (1.00)
- Transportation > Ground (1.00)
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- South America > Brazil > Campos Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 786 > Petronius Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 392 > Appomattox Field (0.99)
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Several approaches that use the activity-coefficient model assume the oil and asphaltene as two pseudocomponents: one component representing the deasphalted oil and the other the asphaltenes. Andersen and Speight[69] provided a review of activity models in this category. Other approaches represent the precipitate as a multicomponent solid.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.98)
- Information Technology > Knowledge Management (0.40)
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Deposition of the high-molecular-weight components of petroleum fluids as solid precipitates in surface facilities, pipelines, downhole tubulars, and within the reservoir are well-recognized production problems. The deposits also can contain resins, crude oil, fines, scales, and water.[1] Asphaltenes and waxes are a general category of solids and, thus, cover a wide range of materials. Understanding the fundamental characteristics that define the nature of asphaltenes and waxes is valuable in reducing or avoiding the production impacts of their deposition. This page examines the general chemical classifications and types of asphaltenes and waxes, in addition to their solidification behaviors.
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.29)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.70)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.69)
- Information Technology > Knowledge Management (0.40)
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The first fracture treatments were pumped just to see if a fracture could be created and if sand could be pumped into the fracture. In 1955, Howard and Fast [1] published the first mathematical model that an engineer could use to design a fracture treatment. The Howard and Fast model assumed the fracture width was constant everywhere, allowing the engineer to compute fracture area on the basis offracture fluid leakoff characteristics of the formation and the fracturing fluid. Modeling of fracture propagation has improved significantly with computing technology and a greater understanding of subsurface data. The Howard and Fast model was a 2D model.
- Information Technology > Modeling & Simulation (0.55)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N2), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. Phase Behavior of Natural-Gas Reservoirs A widely accepted system for categorizing petroleum reservoir fluids is based on five classes: low-shrinkage (crude) oils, high-shrinkage (volatile) oils, retrograde-condensate gases, wet gases, and dry gases. Typical phase diagrams for the gas categories are shown inFigs.
- North America > United States > Texas (0.93)
- North America > United States > Louisiana (0.93)
- North America > United States > Louisiana > Fordoche Field (0.99)
- North America > United States > Louisiana > Cotton Valley Field (0.99)
- Asia > Middle East > Syria > Deir ez-Zor Governorate > Tanek Field (0.93)
- Information Technology > Modeling & Simulation (0.46)
- Information Technology > Knowledge Management (0.40)
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Many important applications of fluid flow in permeable media involve 1D, radial flow. These applications are based on a model that includes many simplifying assumptions about the well and reservoir. These assumptions are introduced as needed to combine the law of conservation of mass, Darcy's law, and equations of state to achieve our objectives. Consider radial flow toward a well in a circular reservoir. Combining the law of conservation of mass and Darcy's law for the isothermal flow of fluids of small and constant compressibility yields the radial diffusivity equation,[1]
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