Question 1 of 7: Reservoir Fluid Fundamentals and Definitions

Question 1: Reservoir Fluid Fundamentals and Definitions (20 marks)

Question text not reproduced: the examination questions are © Engineers and Geoscientists BC. Open the official past paper (linked at the top of this page) to read the question, then follow the worked solution below.

a) PT diagram of a pure component. A pure substance has exactly three phase-boundary curves meeting at a single, invariant triple point: the sublimation curve (solid–vapour equilibrium, rising gently at low $T,p$), the melting (fusion) curve (solid–liquid equilibrium, steep and nearly vertical, rising from the triple point), and the vaporization curve (liquid–vapour equilibrium, running from the triple point up to the critical point, beyond which no liquid/vapour distinction exists).

b) Classification of reservoir fluids. Reservoir fluids are classified by their location relative to the critical point and cricondentherm on the fluid's own $p$–$T$ phase envelope, together with the produced surface gas-oil ratio (GOR) and stock-tank liquid gravity. The four basic types are: black oil (low-GOR, dark, high-API-range liquid; reservoir temperature well below the critical temperature); volatile oil (high-GOR, lighter-coloured liquid; reservoir temperature close to, but below, the critical temperature); retrograde-condensate gas (reservoir temperature between the critical temperature and the cricondentherm, so isothermal depletion crosses the dew-point curve and liquid condenses in the reservoir); and wet gas / dry gas (reservoir temperature above the cricondentherm, so the fluid never enters the two-phase envelope in the reservoir — wet gas still condenses liquid at surface conditions, dry gas does not).

c) Degrees of freedom — n-butane / iso-butane, two phases. Gibbs' phase rule: $F=C-P+2$. This is a two-component mixture ($C=2$: n-butane and iso-butane — the source's repeated "nC$_4$" label for the second component is read as iso-butane, iC$_4$, since a mixture of one pure species with itself cannot form two phases) in two-phase (liquid + vapour) equilibrium, so $P=2$: $F=2-2+2$, giving $\boxed{F=2}$. Two independent intensive variables (e.g. temperature and pressure) fully fix the equilibrium state; once $T$ and $p$ are set, the equilibrium liquid and vapour compositions are determined by the mixture's own phase behaviour.

Definitions (d–h).

d) Retrograde condensation. The anomalous formation of liquid from a gas as pressure is reduced isothermally (the opposite of everyday intuition, where cooling or compressing normally condenses a vapour). It occurs when the reservoir temperature lies between the critical temperature and the cricondentherm of a gas-condensate fluid: depleting the reservoir from above the dew point drives the state point across the dew-point curve into the two-phase region, so liquid drops out of the gas even though the pressure is falling, not rising.

e) Constant composition expansion (CCE). A PVT laboratory test in which a fixed mass (fixed overall composition) of reservoir fluid is loaded into a visual cell at or above the initial reservoir pressure and the cell volume is expanded in steps at constant reservoir temperature, with total cell volume and pressure recorded at each step (no fluid removed). It locates the bubble point (or dew point) as the pressure at which the pressure–volume relationship changes slope, and yields the single-phase (undersaturated) compressibility and the relative oil volume above and below saturation.

f) Undersaturated oil. A reservoir oil whose current pressure is above its bubble-point pressure, so it is holding less dissolved gas than it is thermodynamically capable of holding at that pressure — the oil is single-phase liquid, and no free gas phase exists in the reservoir until pressure declines to the bubble point.

g) Test separator. A calibrated, instrumented surface separator used specifically to sample and measure the well's producing gas-oil ratio and the properties of the separated gas and oil streams under controlled, fixed separator pressure and temperature, distinct from the field production separators that route routine sales gas and oil; the test-separator GOR and stream samples are the reference data used to recombine a representative reservoir-fluid sample for PVT analysis.

h) Sour gas. A natural gas that contains hydrogen sulfide (H$_2$S), often together with other acid gases such as CO$_2$, above the concentration accepted as "sweet"; sour gas is toxic and corrosive, so it requires specialized metallurgy, safety systems (H$_2$S detection, emergency response) and gas-sweetening (e.g. amine treating) before sale, in contrast to "sweet" gas which contains negligible H$_2$S.