This book on PVT and Phase Behaviour Of Petroleum Reservoir Fluids is volume 47 in the Developments in Petroleum Science series. The chapters in the book are: Phase Behaviour Fundamentals, PVT Tests and Correlations, Phase Equilibria, Equations of State, Phase Behaviour Calculations, Fluid Characterisation, Gas Injection, Interfacial Tension, and Application in Reservoir Simulation.
Developments in Petroleum Science, Vol. 47, Suppl. (C), 1998
ISSN: 0376-7361
doi: 10.1016/S0376-7361(98)80023-X
1 Phase Behaviour Fundamentals
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.
1.1 RESERVOIR FLUID COMPOSITION
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 5.3.
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. The sulphur, nitrogen and organometallic compounds of crude oil samples were investigated in projects API-48, API-52 and API-56 respectively. API-60 studied petroleum heavy ends. Nelson [3] gives a review of petroleum chemistry and test methods used in the refining industry.
Highly detailed information on the constituents composing a reservoir fluid is not of very much use in exploration and production processes. Reservoir fluids are commonly identified by their constituents individually to pentanes, and heavier compounds are reported as groups composed mostly of components with equal number of carbons such as
All the compounds forming each single carbon number group do not necessarily possess the same number of carbons as will be discussed in Section 6.1. The most common method of describing the heavy fraction is to lump all the compounds heavier than C6 and report it as C7+.
Hydrocarbon compounds can be expressed by the general formula of CnH2n+Ο with some sulphur, nitrogen, oxygen and minor metallic elements mostly present in heavy fractions. Hydrocarbon compounds are classified according to their structures, which determine the value of Ο. The major classes are paraffins (alkanes), olefins (alkenes), naphthenes, and aromatics. The paraffin series are composed of saturated hydrocarbon straight chains with Ο=2. 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. The olefin series (Ο=0) have unsaturated straight chains and are not usually found in reservoir fluids due to their unstable nature. The naphthenes are cyclic compounds composed of saturated ring(s) with Ο=0. The aromatics (Ο=â6) are unsaturated cyclic compounds. Naphthenes and aromatics form a major part of C6âC11 groups and some of them such as methyl-cyclo-pentane, benzene, toluene and xylene are often individually identified in the extended analysis of reservoir fluids. For example, the structural formulas of the above groups of hydrocarbons with six carbons are shown in Figure 1.1.
Figure 1.1 Structural formula of various groups of hydrocarbons with six carbons.
