Oil Swelling

Key Takeaways

• Formation volume factor (Bo) quantifies oil swelling and is essential for converting surface production to reservoir volumes — Bo is defined as the volume of reservoir fluid at reservoir conditions divided by the volume of stock tank oil at standard conditions; a Bo of 1.3 rb/STB means that one stock tank barrel of oil corresponds to 1.3 reservoir barrels of live oil-plus-dissolved-gas in the formation; when estimating original oil in place (OOIP) from pore volume calculations, the reservoir hydrocarbon pore volume is divided by Bo to convert to stock tank barrels; when calculating produced reservoir volumes from measured surface production, daily surface production in STB is multiplied by Bo to get the reservoir volume being depleted; these conversions appear in every material balance calculation and reservoir simulation model, making Bo one of the most frequently used PVT parameters in reservoir engineering.
• Oil swelling from CO2 injection is a key EOR mechanism that improves recovery beyond water flooding — when CO2 at miscible conditions dissolves into reservoir oil, the oil volume increases significantly (swelling factors of 1.2-1.6 are common at minimum miscibility pressure conditions); this swelling acts like an additional drive mechanism that pushes oil toward producing wells; simultaneously, CO2 dissolution reduces oil viscosity substantially (sometimes by more than an order of magnitude for heavy oils), improving the mobility ratio of the CO2-oil displacement compared to water flooding; the combination of swelling, viscosity reduction, and eventual miscibility (elimination of capillary trapping) accounts for the superior displacement efficiency of CO2 EOR compared to conventional water flooding in reservoirs above minimum miscibility pressure.
• Swelling tests in the laboratory quantify crude oil response to injection gas before field implementation — a swelling test (or solubility test) is a PVT experiment where a crude oil sample is pressurized with the proposed injection gas (CO2, hydrocarbon solvent, nitrogen) and the resulting oil volume and fluid properties are measured at each pressure step; the test produces a swelling factor versus pressure relationship that characterizes how much volume increase (and viscosity reduction) the crude oil experiences as it dissolves more gas; swelling test results are used to validate reservoir simulation fluid property models and to confirm that the injection gas will provide the expected recovery improvement; swelling tests are a standard part of the EOR feasibility evaluation workflow before committing to field-scale CO2 or solvent injection programs.
• Oil shrinkage is the inverse of swelling — the reduction in oil volume when it is produced from the reservoir to surface conditions is sometimes called shrinkage, with the shrinkage factor being 1/Bo; a Bo of 1.3 corresponds to a shrinkage factor of 0.77, meaning the oil shrinks to 77% of its reservoir volume when produced to surface; the shrinkage is caused by the release of dissolved gas (solution GOR) and thermal contraction as oil cools from reservoir temperature to surface temperature; understanding both swelling (at reservoir conditions) and shrinkage (during production to surface) requires the full PVT characterization of reservoir fluid properties, typically obtained through recombined wellhead samples analyzed in a PVT laboratory using constant composition expansion and differential liberation experiments.
• Below-bubble-point production causes oil to "de-swell" as dissolved gas comes out of solution — when reservoir pressure drops below the bubble point of the oil (the pressure at which dissolved gas starts exsolving), gas bubbles form in the pore space and the oil volume decreases as dissolved gas is lost; the oil in the reservoir becomes "dead" (shrinks below Bo at bubble point) and the released gas forms a free gas phase that changes both the relative permeability to oil and the drive mechanism from solution-gas to an increasingly gas-drive process; reservoir engineers track the producing GOR and monitor whether it exceeds the solution GOR as an indicator of whether reservoir pressure is declining below the bubble point and causing this below-bubble-point de-swelling in the reservoir.