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By Ali Danesh. Petroleum reservoir fluids are composed mainly of hydrocarbon constituents. Water is also present in gas and oil reservoirs in an interstitial form. The influence of water on the phase behaviour and properties of hydrocarbon fluids in most cases is of a minor consideration.

The phase behaviour of oil and gas, therefore, is generally treated independent of the water phase, unless water-hydrocarbon solid structures, known as hydrates, are formed. The behaviour of a hydrocarbon mixture at reservoir and surface conditions is determined by its chemical composition and the prevailing temperature and pressure.

This behaviour is of a prime consideration in the development and management of reservoirs, affecting all aspects of petroleum exploration and production. Although a reservoir fluid may be composed of many thousands of compounds, the phase behaviour fundamentals can be explained by examining the behaviour of pure and simple multicomponent mixtures.

The behaviour of all real reservoir fluids basically follows the same principle, but to facilitate the application of the technology in the industry, reservoir fluids have been classified into various groups such as the dry gas, wet gas, gas condensate, volatile oil and black oil.

There are various hypotheses regarding the formation of petroleum from organic materials. These views suggest that the composition of a reservoir fluid depends on the depositional environment of the formation, its geological maturity, and the migration path from the source to trap rocks [ 1].

Reservoir gasses are mainly composed of hydrocarbon molecules of small and medium sizes and some light non-hydrocarbon compounds such as nitrogen and carbon dioxide, whereas oils are predominantly composed of heavier compounds.

Fluids advancing into a trapping reservoir may be of different compositions due to being generated at different times and environments. Hence, lateral and vertical compositional variations within a reservoir will be expected during the early reservoir life.

Reservoir fluids are generally considered to have attained equilibrium at maturity due to molecular diffusion and mixing over geological times. However, there are ample evidences of reservoirs still maintaining significant compositional variations, particularly laterally as the diffusive mixing may require many tens of million years to eliminate compositional heterogenuities [ 2]. Furthermore, the pressure and the temperature increase with depth for a fluid column in a reservoir.

This can also result in compositional grading with depth. For operational purposes, this behaviour is of considerable interest for near critical fluids, and oils containing high concentrations of asphaltic material. The compositional grading and its estimation based on thermodynamic concepts will be discussed in Section 5. The crude oil composition is of major consideration in petroleum refining. A number of comprehensive research projects sponsored by the American Petroleum Institute have investigated crude oil constituents and identified petroleum compounds.

API-6 studied the composition of a single crude oil for 40 years. API studied petroleum heavy ends. Nelson [ 3] gives a review of petroleum chemistry and test methods used in the refining industry. All the compounds forming each single carbon number group do not necessarily possess the same number of carbons as will be discussed in Section 6. The major classes are paraffins alkanes , olefins alkenes , naphthenes, and aromatics.

Light paraffins in reservoir fluids are sometimes identified and reported as those with a single hydrocarbon chain, as normal, and others with branched chain hydrocarbons, as iso. For example, the structural formulas of the above groups of hydrocarbons with six carbons are shown in Figure 1. Figure 1. As reservoir hydrocarbon liquids may be composed of many thousand components, they cannot all be identified and measured. However, the concentration of hydrocarbon components belonging to the same structural class are occasionally measured and reported as groups, particularly for gas condensate fluids.

The test to measure the concentration of p araffins, n aphthenes, and a romatics as groups is commonly referred to as the PNA test [ 4].

Further information on the structure of reservoir fluid compounds and their labelling according to the IUPAC system can be found in [5]. The compositional analysis of reservoir fluids and their characterisation will be discussed in Chapter 6. Nitrogen, oxygen and sulphur are found in light and heavy fractions of reservoir fluids. Gas reservoirs containing predominantly N2, H2S, or C02 have also been discovered.

Polycyclic hydrocarbons with fused rings which are more abundant in heavier fractions may contain N, S, and O. These compounds such as carboids, carbenes, asphaltenes and resins are identified by their solubility, or lack of it, in different solvents [ 6]. The polar nature of these compounds can affect the properties of reservoir fluids, particularly the rock-fluid behaviour, disproportionally higher than their concentrations [7]. These heavy compounds may be present in colloidal suspension in the reservoir oil and precipitate out of solution by changes in the pressure, temperature or compositions occurring during production.

Reservoir hydrocarbons exist as vapour, liquid or solid phases. A phase is defined as a part of a system which is physically distinct from other parts by definite boundaries. A reservoir oil liquid phase may form gas vapour phase during depletion.

The evolved gas initially remains dispersed in the oil phase before forming large mobile clusters, but the mixture is considered as a two-phase system in both cases. The formation or disappearance of a phase, or variations in properties of a phase in a multi-phase system are rate phenomena. The subject of phase behaviour, however, focuses only on the state of equilibrium, where no changes will occur with time if the system is left at the prevailing constant pressure and temperature.

A system reaches equilibrium when it attains its minimum energy level, as will be discussed in Chapter 3. The assumption of equilibrium between fluid phases in contact in a reservoir, in most cases, is valid in engineering applications. Fluids at equilibrium are also referred to as saturated fluids.

The state of a phase is fully defined when its composition, temperature and pressure are specified. All the intensive properties for such a phase at the prevailing conditions are fixed and identifiable. The intensive properties are those which do not depend on the amount of material contrary to the extensive properties , such as the density and the specific heat.

The term property throughout this book refers to intensive properties. At equilibrium, a system may form of a number of co-exiting phases, with all the fluid constituents present in all the equilibrated phases.

The number of independent variables to define such a system is determined by the Gibbs phase rule described as follows. However, the temperature, pressure, and chemical potential of each component throughout all phases should be uniform at equilibrium conditions, as will be described in Chapter 3.

Hence, the number of independent variables, or so-called the degrees of freedom, F, necessary to define a multiphase system is given by,:. For a single-component pure system, the degrees of freedom is equal to three minus the number of phases. The state of the equilibrium of a vapour-liquid mixture of a pure fluid, therefore, can be determined by identifying either its pressure or its temperature.

The phase behaviour of a pure compound is shown by the pressure-temperature diagram in Figure 1. All the conditions at which the vapour and liquid phases can coexist at equilibrium are shown by the line AC. Any fluid at any other pressure-temperature conditions, is unsaturated single phase as required by the phase rule. The fluid above and to the left of the line is referred to as a compressed or under saturated liquid, whereas that below and to the right of the line is called a superheated vapour or gas.

The line AC is commonly known as the vapour pressure curve, as it shows the pressure exerted by the vapour coexisting with its liquid at any temperature.

The temperature corresponding to the atmospheric pressure is called the normal boiling point or simply the boiling point of the compound. The boiling point, Tb, of some compounds found in reservoir fluids are given in Table A.

McGraw-Hill Companies Copyright. The line AB on Figure 1. The intersection of the vapour-liquid and liquid-solid lines is the triple point. It is the only point where the three phases can coexist for a pure system.

The line AD is the solid-vapour equilibrium line or the sublimation curve. The solid carbon dioxide dry ice vaporising into its gaseous form is a common example of this region of the phase behaviour diagram. The variation of saturated fluid density with temperature for a pure compound is shown in Figure 1. The densities of vapour and liquid phases approach each other as the temperature increases.

They become equal at conditions known as the critical point. All the differences between the phases are reduced as the system approaches the critical point. Indeed, the phases become the same and indistinguishable at the critical point. All the compounds show a similar trend, that is, the vapour and liquid densities become equal at the critical point.

Other properties also show the same trend. The critical temperature, Tc, and the critical pressure, Pc, are the maximum temperature and pressure at which a pure compound can form coexisting phases. The terms vapour and liquid are referred to the less and the more dense phases of a fluid at equilibrium. Hence, a pure compound at a temperature above its critical value cannot be called either liquid or vapour. The continuity of vapour and liquid is schematically shown in Figure 1.

The density at each point is shown by the shading intensity, where the darker shading corresponds to a higher density. The discontinuity across the vapour-pressure curve becomes less significant as the temperature increases and vanishes above the critical point. The superheated vapour E can be changed gradually to the compressed liquid F, through an arbitrary path EGF, without any abrupt phase change. The pressure-volume diagram of a pure substance is shown in Figure 1.

Consider the compressed liquid, Point A, at a temperature below the critical temperature. The reduction of fluid pressure at constant temperature increases its volume.

As the liquid is relatively incompressible the fluid expansion is small until the vapour pressure is reached, at Point B, where the first bubble evolves. Further expansion of the system results in changing the liquid into the vapour phase. For a pure substance the pressure remains constant and equal to the vapour pressure, a consequence of the phase rule, until the last drop of the liquid vaporises, Point D. This point, where the vapour is in equilibrium with an infinitesimal amount of liquid is called the dew point.

The bubble point and dew point curves appear as a single vapour pressure curve on a pressure-temperature plot for a pure compound, Figure 1. The change of phase from liquid to vapour is accompanied by a large increase in volume at low temperatures Figure 1. The expansion reduces as the temperature approaches the critical point.

Indeed the system changes from all liquid into all vapour, or vice versa, without any change in the mixture volume at the critical point. An isothermal expansion of a fluid at a temperature above the critical temperature does not result in any phase change, Point N.


PVT and Phase Behaviour Of Petroleum Reservoir Fluids

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PVT and Reservoir Fluid Phase Behaviour



PVT and Phase Behaviour Of Petroleum Reservoir Fluids, Volume 47




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