Composition of reservoir fluids

Oil and natural gas are natural mixtures in which hydrocarbons dominate. Hydrocarbons are compounds of carbon and hydrogen. By mass, oil is usually 83–87% carbon and 10–14% hydrogen. The rest is sulfur, nitrogen, oxygen and traces of metals. Oil contains hundreds and thousands of individual compounds. An engineer does not need each of them. What matters is how the mixture as a whole behaves when pressure and temperature change.

The state of a mixture depends first of all on the size of its molecules. A mixture of small molecules such as methane and ethane is a gas under ordinary conditions. A mixture of larger molecules is a liquid. The heaviest components — resins, asphaltenes and high-molecular-weight paraffins — are, in pure form, solid or as thick as bitumen (tar). In the reservoir, at high pressure and temperature, the mixture may be single-phase (all in one state). At the surface it may separate into gas and liquid. The topic Phase behaviour: pure substances and binary mixtures explains how this happens.

The pores of a reservoir always contain water as well as hydrocarbons. This is irreducible water, which the oil and gas could not push out when they filled the trap (the rock structure that holds oil and gas). Capillary forces (the forces of surface tension in narrow pores) hold it in place (see Fluid saturation). Formation water is also a reservoir fluid, but we describe its composition differently: by the dissolved salts.

A carbon atom forms four chemical bonds. We tell hydrocarbons apart by two features. The first is how the carbon atoms are joined: in an open chain or in a ring. The second is what bonds there are between them: only single bonds (such compounds are called saturated), or also double and triple bonds (unsaturated).

Alkanes, or paraffins, are the most widespread class. Methane, ethane, propane and the butanes are gases under normal conditions. From pentane up to about hexadecane $\mathrm{C_{16}}$ they are liquids. Normal (straight-chain) alkanes from about $\mathrm{C_{17}}$ upward are solid at room temperature: this is paraffin wax. Dissolved in oil, the wax does no harm. But when the oil cools in the well and in pipelines, the wax crystallises and deposits on the walls (Retrograde condensation, wax, asphaltenes and high-pressure fluids).

From butane onwards, the same atoms can be joined in different ways. The result is isomers: substances with the same composition but a different structure and different properties. Normal butane boils at −0.5 °C, and branched isobutane at −11.7 °C. The number of isomers grows quickly with the number of carbon atoms. Pentane has 3, heptane has 9, decane has 75, and the alkane $\mathrm{C_{20}}$ has more than 366 thousand. This is why we cannot describe the heavy part of oil compound by compound.

Cycloalkanes, called naphthenes in petroleum practice, have their carbon atoms closed into rings of five or six: cyclopentane, cyclohexane and their derivatives with side chains. Aromatics contain a benzene ring. The simplest are benzene, toluene and the xylenes. For the same number of carbon atoms, aromatics are noticeably denser than alkanes. The specific gravity of liquid n-hexane is about 0.66, of cyclohexane 0.78, and of benzene 0.88.

The heaviest part of oil is the resins and asphaltenes. These are large molecules made of several fused rings, with atoms of sulfur, nitrogen, oxygen and metals (vanadium and nickel). Their share decides how dark, dense and viscous the oil is. Asphaltenes stay in the oil in a colloidal state (as tiny suspended particles), surrounded by resins. They may precipitate (settle out as a solid) when the pressure falls or when the oil is mixed with injected gas or carbon dioxide.

Besides hydrocarbons, reservoir fluids almost always contain non-hydrocarbon components. There are usually few of them. But they decide equipment corrosion, safety, the processing of the produced fluids and their price, and sometimes the phase behaviour of the fluid (whether it is gas, liquid or both).

Carbon dioxide is not aggressive in itself. But in water it forms carbonic acid, and this causes carbon dioxide corrosion of carbon steel. It dissolves readily in oil, lowers its viscosity and increases its volume. This is the basis of $\mathrm{CO_2}$ injection for enhanced oil recovery. At the same time, carbon dioxide can cause asphaltenes to precipitate.

Hydrogen sulfide is dangerous in three ways. It is poisonous, it is flammable, and in the presence of water it causes corrosion and sulfide stress cracking. This is the brittle failure of loaded steel (it breaks suddenly, with no stretching first), especially high-strength steel. We choose materials for hydrogen sulfide environments according to a dedicated international standard (ISO 15156, also known as NACE MR0175). The measure of how aggressive the gas is the partial pressure of hydrogen sulfide: the product of its mole fraction in the gas and the absolute pressure of the gas. For carbon and low-alloy steels, we must confirm resistance to sulfide stress cracking from as little as about 0.3 kPa (0.05 psi).

We can write the composition of a mixture in three ways: in mole fractions, mass fractions or volume fractions. The numbers come out different.

Mole fraction $z_i$

The share of the moles (that is, the molecules) of component $i$ among all the moles of the mixture. The mole fractions add up to one. We write $y_i$ for the gas phase, $x_i$ for the liquid phase and $z_i$ for the mixture as a whole. In percent, it is mole percent, mol%.

Mass fraction $w_i$

The share of the mass of the mixture that belongs to the component (wt%). We use mass fractions, for example, to report the results of distilling the heavy part of oil.

Volume fraction

The share of the volume that the component would occupy on its own at the same conditions (vol%). For ideal gases it equals the mole fraction: equal volumes of gases at the same pressure and temperature contain the same number of molecules. For liquids it does not. Equal volumes of different liquids contain different numbers of molecules, and, besides, volumes do not add up exactly on mixing.

We do phase-equilibrium and gas-law calculations in mole fractions. The pressure of a gas, solubility and the distribution of components between phases depend on the number of molecules, not on their mass. That is why a gas analysis is reported in mole percent (for a gas, the same as volume percent). To get to mass, we need the molar masses of the components.

We do not get the composition of reservoir oil from one analysis of a sample under pressure. Usually we analyse the gas and the liquid separately: from the separator, or after the bottomhole sample (a sample taken at the bottom of the well) has been degassed in the laboratory. Then we recombine them, which means recalculating them to the reservoir mixture using the measured gas–oil ratio (Reservoir fluid sampling; a worked calculation is in the lesson on fluid types).

We analyse the gas by chromatography (a method that separates a mixture into its components). We measure each of the non-hydrocarbon gases and each hydrocarbon up to the pentanes separately, and the heavier ones in groups. We divide the liquid into fractions by carbon number (the number of carbon atoms in a molecule). The $\mathrm{C_8}$ fraction includes all the compounds that boil between normal heptane and normal octane: alkanes, naphthenes and aromatics alike. Modern analysis goes up to $\mathrm{C_{30}}$ and beyond. But we lump everything heavier than the chosen limit into a single plus fraction, C7+, or C10+, C20+ and so on.

We know the properties of the individual components precisely, but the C7+ fraction is different for every oil. Two measured numbers describe it: the molar mass $M_{7+}$ and the specific gravity $\gamma_{7+}$ (relative to water at 60 °F). The molar mass reflects the size of the molecules, which means how volatile (how easily evaporating) the fraction is. At the same molar mass, the density tells us the type of hydrocarbons: an aromatic fraction is denser than a paraffinic one. For oils $M_{7+}$ is typically about 180–280 g/mol, and for gas condensates about 110–170 g/mol.

For equation-of-state calculations (Cubic equations of state) we divide the C7+ fraction into parts. The mole fraction of the fractions falls in a regular way as the carbon number grows, roughly exponentially. This lets us extend the analysis beyond its limit. Then we lump neighbouring fractions together again into 3–5 pseudo-components: imaginary substances with average properties. A typical fluid model has 8–15 components. The calculation stays accurate enough and does not take too long.

For complex fluids, such as high-pressure, high-temperature gas condensates and oils prone to paraffin and asphaltene deposition, $M_{7+}$ and $\gamma_{7+}$ alone are not enough. Then we find the group composition of the heavy fractions: the shares of paraffins, naphthenes and aromatics (PNA analysis, from paraffins, naphthenes, aromatics). To assess the stability of the asphaltenes, we find the shares of saturates, aromatics, resins and asphaltenes (SARA analysis, from saturates, aromatics, resins, asphaltenes).

The most readily available characteristic of produced oil is the density of the stock-tank oil. In Russian-language practice, we give it in kg/m³ at 20 °C (sometimes at 15 °C). In international practice, it is given as the specific gravity $\gamma_o$ (the density relative to water) at 60 °F (15.6 °C), or in degrees API (after the American Petroleum Institute).

At the drilling rig, we also judge how light an oil is from indirect signs. We examine cuttings (rock chips brought up by the drilling fluid) and core under an ultraviolet lamp. Oil glows, and the colour of the glow changes from dull brown for heavy oils to yellow and bluish-white for light ones. The refractive index of oil (how strongly it bends light) also rises with its density. These are quick qualitative estimates, not a substitute for analysis.