Question 1 of 7: Black Oil PVT Experiments

Question 1: Black Oil PVT Experiments (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.

Part (a) — Flash vaporization (flash liberation) test. A representative bottom-hole (or recombined surface) sample is loaded into a visual PVT cell at the measured reservoir temperature and at a pressure at or above the initial reservoir pressure, so the fluid starts as a single liquid phase. The cell pressure is then lowered in stages by withdrawing mercury (or advancing a piston), and at each step the cell is agitated to equilibrium and the total volume is recorded. Crucially, no fluid is removed from the cell at any stage — all gas that comes out of solution below the bubble point stays in contact with the remaining liquid, so the overall composition of the system is held constant throughout the test. The pressure is reduced this way from above the bubble point, through the bubble point (identified as the pressure at which the slope of the volume–pressure curve breaks sharply, since only liquid compressibility acts above it and both liquid expansion and gas evolution act below it), down to atmospheric pressure. The data produced are the relative volume curve $V_{rel}(p) = V(p)/V_{sat}$ and the bubble-point pressure $p_b$.

Because composition never changes, a flash test is a constant-composition expansion (CCE): it measures $p_b$ and the isothermal compressibility of the undersaturated liquid accurately, but because the liberated gas is never removed, it does not reproduce what actually happens as oil flows from the reservoir to the stock tank (where gas is progressively removed at each separator stage). The flash test is therefore used chiefly for $p_b$ and single-phase liquid compressibility, and as the basis for a separate single-stage or multi-stage "flash" of a produced fluid to atmospheric conditions when field separator data are combined with lab data.

Part (b) — Differential liberation (differential expansion) test. The same charged cell starts identically at or above $p_b$ at reservoir temperature. Pressure is again reduced in steps, but below the bubble point the liberated gas is expelled from the cell at constant pressure after each pressure drop, so that only the remaining liquid (now a smaller, gas-depleted system) is compressed to the next pressure step. At each stage the liberated gas volume is measured at cell conditions and then at standard conditions (giving its density and a running solution gas–oil ratio), and the shrinkage of the remaining oil is measured, down to atmospheric pressure and reservoir temperature, at which point the remaining "residual oil" volume is corrected to 60°F stock-tank conditions to compute $B_{ob}$, $B_o(p)$, $R_s(p)$ and the oil density/gas gravity at each stage.

Because gas is removed as it evolves, a differential test is a series of flash liberations at progressively poorer conditions and its liquid composition becomes progressively heavier (leaner in light ends) exactly as the reservoir fluid does when free gas separates from the oil and migrates away in the pore space while pressure declines below $p_b$ — this is the process the reservoir itself undergoes. The differential test therefore supplies the PVT properties ($B_o$, $R_s$, $B_g$, oil and gas density/viscosity) used directly in reservoir material-balance and simulation below the bubble point. Because neither test alone matches what happens at the wellbore/surface (where the produced stream flashes through separators, not a slow differential process), standard practice combines both: the differential data are used for below-$p_b$ shrinkage/solution-GOR shape, then rescaled ("adjusted") using a laboratory or field separator flash test (as in Question 3) so that the reported $B_o$ and $R_s$ match stock-tank conditions actually achieved in the field separator train.