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The calculation of reserves in an oil reservoir or the determination of its performance requires knowledge of the fluid's physical properties at elevated pressure and temperature. Of primary importance are those properties including bubblepoint pressure, solution gas/oil ratio (GOR), and formation volume factor (FVF). In addition, viscosity and surface tension must be determined for calculations involving the flow of oil through pipe or porous media. Ideally, these properties are determined from laboratory studies designed to duplicate the conditions of interest; however, experimental data are quite often unavailable because representative samples cannot be obtained or the producing horizon does not warrant the expense of an in-depth reservoir fluid study. In these cases, pressure-volume-temperature (PVT) properties must be determined by analogy or through the use of empirically derived correlations.

Generally speaking, intellectual property is any product of the human intellect that the law protects from unauthorized use. Creators of intellectual property have exclusive ownership and rights to their intangible assets, which in the realm of the oil and gas industry usually applies to discoveries, inventions, words, phrases, and designs. Intellectual property is traditionally composed of four categories: patents, copyright, trademarks, and trade secrets. Trademarks are names, words, symbols, designs, or combinations of these, that are used to distinguish the goods or services of one company from those of another company. Copyrights protect creative works, like brochures or technical descriptions, from being copied without the creator's permission.

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.

Understanding the mechanisms and potential for wax precipitation are key factors in preventing production problems as a result of wax. Wax precipitation has a strong dependence on temperature and weak dependence on pressure. This page presents a general form of the thermodynamic relation used to define the K values for solid and liquid phases in equilibrium, and the effect of different simplifying assumptions and thermodynamic descriptions of the phases involved on the model results are examined. The thermodynamic basis of solid/liquid equilibrium of components in a melt or dissolved in a solution is well established and is described in many standard texts (e.g., Prausnitz et al.[1]). The basic principles continue to be applied to more complex systems as researchers attempt to develop more accurate models of solid wax precipitation. Lira-Galeana and Hammami[2] reviewed experimental techniques and thermodynamic models for studying wax precipitation in petroleum fluids. The predictive capability of the thermodynamic models is affected both by the form and assumptions of the models themselves and the characterization procedures used to quantify the number and properties of wax forming components present in a fluid. Thermodynamic models for predicting wax precipitation may be derived assuming single-component or multicomponent, single-phase or multiphase solid deposits.

Interfacial or surface tension exists when two phases are present. These phases can be gas/oil, oil/water, or gas/water. Interfacial tension is the force that holds the surface of a particular phase together and is normally measured in dynes/cm. It is a function of pressure, temperature, and the composition of each phase. Two forms of correlations for calculating gas/oil surface tension have been developed.

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.

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.

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Oil, gas, water, steel, and rock are not always chemically inert under oil/gas production conditions. Their mutual interactions, induced in part by changes in pressure and temperature, can lead to the accumulation of solids, both organic and inorganic (scaling) within the production system, as well as deterioration of the metals that the fluids contact (corrosion). This chapter discusses these effects in terms of root causes, the operational difficulties resulting, and the principles/methods that have been used to cope. Case histories are not presented in any detail, but references are given to specific papers dealing with cause/effect/cure examples. It is assumed that the reader is not an expert in things chemical but does have a passing acquaintance with the jargon of chemistry and with some of the general principles underlying chemical processes.