Petroleum reservoir fluids state

Application of a Generalized Equation of State to Petroleum Reservoir Fluids... 

Although the equation of state can be and has been used to predict phase behavior for petroleum reservoir fluids for which no physical property data are available, it is recommended that some data, at least a saturation pressure, be measured in addition to a detailed component analysis of the fluid. This is particularly recommended when expensive compositional model studies are to be performed. 

Reservoir fluids contain a variety of substances of diverse chemical nature that include hydrocarbons and nonhydrocarbons. Hydrocarbons range from methane to substances that may contain 100 carbon atoms, even when these substances are in the form of singly dispersed molecules (i.e., monomers). Nonhydrocarbons include substances such as N2, CO2, H2S, S, H2O, He, and even traces of Hg. The chemistry of hydro-carbon-reservoir fluids is very complex. Methane, often a predominant component of natural gases and petroleum-reservoir fluids, is a gas, nCg and hydrocarbons as heavy as may be in the liquid state, and normal paraffins heavier than may be in the solid state at room temperatures. However, the mixture of these hydrocarbons may be in a gaseous or liquid state at the pressures and temperatures often encountered in hydrocarbon reservoirs. The mixture may also be a solid as will be seen in Chapter 5. The majority of reservoirs fall within the temperature range of 80 to 350 F, and the pressure range of 50 to 20,000 psia. When steam is injected into hydrocarbon reservoirs, the temperature may exceed 550 F and for in-situ combustion, the temperature may be even higher. 

Yarborough, L. Application of a Generalized Equation of State to Petroleum Reservoir Fluids, Equations of State in Engineering, Advances in Chemistry Series, K.C. Chao and R.L. Robinson (eds.), American Chem. Soc., Washington, DC, vol. 182, p.385,1979. 

In part II of the present report the nature and molecular characteristics of asphaltene and wax deposits from petroleum crudes are discussed. The field experiences with asphaltene and wax deposition and their related problems are discussed in part III. In order to predict the phenomena of asphaltene deposition one has to consider the use of the molecular thermodynamics of fluid phase equilibria and the theory of colloidal suspensions. In part IV of this report predictive approaches of the behavior of reservoir fluids and asphaltene depositions are reviewed from a fundamental point of view. This includes correlation and prediction of the effects of temperature, pressure, composition and flow characteristics of the miscible gas and crude on (i) Onset of asphaltene deposition (ii) Mechanism of asphaltene flocculation. The in situ precipitation and flocculation of asphaltene is expected to be quite different from the controlled laboratory experiments. This is primarily due to the multiphase flow through the reservoir porous media, streaming potential effects in pipes and conduits, and the interactions of the precipitates and the other in situ material presnet. In part V of the present report the conclusions are stated and the requirements for the development of successful predictive models for the asphaltene deposition and flocculation are discussed. 

Below the bubble-point, pressure gas percolates out of the oil phase, coalesces and displaces the crude oil. The gas phase, which is much less viscous and thus more mobile than the oil phase, fingers through the displaced oil phase. In the absence of external forces, the primary depletion inefficiently produces only 10 to 30 percent of the original oil in place. In the secondary stage of production, water is usually injected to overcome the viscous resistance of the crude at a predetermined economic limit of the primary depletion drive. The low displacement efficiencies, 30 to 50 percent, of secondary waterfloods are usually attributed to vertical and areal sweep inefficiencies associated with reservoir heterogeneities and nonconformance in flood patterns. Most of the oil in petroleum reservoirs is retained as a result of macroscopic reservoir heterogeneities which divert the driving fluid and the microscopically induced capillary forces which restrict viscous displacement of contacted oil. This oil accounts for approximately 70 percent, or 300 x 10 bbl, of the known reserves in the United States. 

Hoffman, E. J. Unsteady-State Fluid Flow Analysis and Applications in Petroleum Reservoir Behavior. Amsterdam, the Netherlands Elsevier Science, 1999. 

Do not attempt to compare fluid types as defined here with the reservoir descriptions as defined by the state regulatory agencies which have jurisdiction over the petroleum industry. The legal and regulatory definitions of oil, crude oil, gas, natural gas, condensate, etc., usually do not bear any relationship to the engineering definitions given here. In fact, the regulatory definitions are often contradictory. 

This book evolved from notes prepared and developed by me over the past six years. This material forms the subj ect matter for a one-semester petroleum engineering course at The Pennsylvania State University. This course along with one dealing with the fundamental properties of reservoir rocks and rook-fluid systems are prerequisites for more advanced courses in reservoir engineering. These basic courses are an introduction to the fundamentals which must be mastered by the student before the treatment of more complex systems can be attempted. 

Components in a gas-condensate fluid contain hydrocarbons from methane, C, ethane, C2, and other hydrocarbons as heavy as or Qo or even heavier. Reservoir crudes may contain hydrocarbons as heavy as C oo- At room temperature (75T) and atmospheric pressure, Cl, C2, C3, and C4 are in the gas state, nC to nC- are in the liquid state, and normal alkanes heavier than nC- are in the solid state. The broad volatility and melting-point range of these hydrocarbon components found in petroleum fluids cause formations of gas, liquid, and solid phases in response to changes in pressure, temperature, or composition. Let us consider a mixture of two hydrocarbons—nC and nC. The melting-point temperature of nC. is 57" C at atmospheric pressure. The solubility of n Cqs in nC at atmospheric pressure is 0.5 mole percent at 14"C. At 40"C and atmospheric pressure, the solubility of nC2R in increases to 12 mole percent. [it is therefore natural that when the temperature falls, heavy hydrocarbons in a crude or even a gas condensate may precipitate as wax crystals. In the petroleum industry, wax precipitation is undesirable because it may plug the pipeline and processing equipment.)... 

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