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+ξ 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 ξ. The major classes are paraffins (alkanes), olefins (alkenes), naphthenes, and aromatics. The paraffin series are composed of saturated hydrocarbon straight chains with ξ=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 (ξ=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 ξ=0. The aromatics (ξ=−6) are unsaturated cyclic compounds. Naphthenes and aromatics form a major part of C6−C11 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.

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 paraffins, naphthenes, and aromatics 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.

1.2 PHASE BEHAVIOUR

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.

A phase composed of N components is fully defined by its number of moles plus two thermodynamic functions, commonly temperature and pressure, that is, by N+2 variables. The intensive properties are, however, determined by only N+1 variables as the concentration of components are not all independent, but constrained by,

     (1.1)

where, xi is the mole fraction of component i. Thus, for a system with κ phases, the total number of variables are equal to κ(N+1). However, the temperature, pressure, and chemical potential...