Solubility

Key Takeaways

• Gas solubility in crude oil, quantified by the solution gas-oil ratio (GOR or Rs), is governed by Henry's Law at low pressures (where the amount of gas dissolved is proportional to pressure) and by more complex equations of state at high pressures; the solution GOR represents the volume of gas (measured at standard conditions) that is dissolved in one stock tank barrel of oil at reservoir pressure and temperature, and it ranges from near zero for dead oils with minimal dissolved gas to over 3,000 scf/STB for highly volatile oils and condensates approaching the critical point; when reservoir pressure declines below the bubble point pressure during production, the dissolved gas begins to evolve from the oil as a free gas phase, driving solution gas drive production and causing the GOR at the surface separator to increase over time; the Standing correlation (1947) and more modern Vasquez-Beggs and Glaso correlations are used to estimate Rs as a function of API gravity, gas specific gravity, temperature, and pressure when laboratory PVT measurements are not available, and reservoir simulation requires accurate Rs correlations as the equation of state inputs that govern the partitioning of components between the oil and gas phases in the reservoir model.
• CO2 solubility in formation water and crude oil is the governing factor in carbonate scale formation (sour water corrosion), reservoir souring in CO2-EOR projects, and the trapping of injected CO2 in carbon storage formations: CO2 dissolves in water to form carbonic acid (H2CO3), which equilibrates with bicarbonate (HCO3-) and carbonate (CO3-2) ions at pH-dependent concentrations; as CO2 partial pressure decreases along the production path (lower total pressure, degassing of CO2 from the water phase), the equilibrium shifts and bicarbonate precipitates as calcium carbonate scale (calcite) at the pressure and temperature conditions where the Langelier saturation index exceeds zero; CO2 solubility in water increases with pressure (approximately 1.45 volume CO2 per volume water at 20 degrees C and 50 bar) and decreases with temperature and salinity, which means CO2 stored in deep saline aquifers (high pressure, high temperature, high salinity) has lower solubility than the formation water could accommodate at shallower, cooler conditions, but over geological time CO2 dissolves into the formation brine and then reacts with silicate minerals to precipitate as calcite and siderite, achieving mineral trapping that is the most permanent form of geological CO2 storage.
• Wax solubility in crude oil determines the wax appearance temperature (WAT, also called the cloud point) — the temperature below which paraffin wax crystals begin to precipitate from solution as the crude oil cools along the production path from reservoir temperature to ambient conditions: wax is fully dissolved in oil at reservoir temperature (where the oil is well above its WAT) but comes out of solution as the oil cools during flow up the wellbore and through subsea flowlines; the WAT of a crude oil depends on the concentration and chain-length distribution of the wax components (primarily n-paraffins with carbon numbers C18-C60), with heavier wax components (higher carbon number) having lower solubility at any given temperature and precipitating first; flow assurance engineers must design heated or insulated flowlines, chemical wax inhibitor injection programs, or pigging schedules to prevent wax deposition from restricting or blocking production in cold-environment offshore fields where the flowline temperature can drop below the WAT; wax solubility is measured in the laboratory by ASTM D2500 (cloud point method), ASTM D5853 (pour point), differential scanning calorimetry (DSC), or cross-polarization microscopy that detects the onset of wax crystal nucleation.
• Scale mineral solubility in formation water determines the scaling tendency of the produced water system, with the Langelier Saturation Index (LSI) for carbonate scale and the Ryznar Stability Index providing simple screening tools for calcium carbonate scaling tendency based on the saturation ratio of the actual calcium and carbonate ion concentrations to their solubility product (Ksp): when the ionic product [Ca2+][CO3-2] exceeds the Ksp of calcite (approximately 3.3 x 10-9 at 25 degrees C, increasing strongly with temperature for most sparingly soluble salts), the solution is supersaturated and scale will tend to precipitate; barium sulfate (barite) scale is particularly problematic in offshore waterfloods because barite has extremely low solubility (Ksp approximately 1.1 x 10-10 at 25 degrees C) and the mixing of barium-rich formation water with sulfate-rich injected seawater creates a mixed water with ion product orders of magnitude above the Ksp, driving rapid and essentially irreversible barite precipitation that cannot be dissolved by acid treatment (unlike carbonate scale which dissolves readily in HCl); scale inhibitor dosing rates are designed by calculating the saturation indices for all relevant scale minerals at the mixing conditions and selecting inhibitor concentrations above the minimum inhibitory concentration required to prevent nucleation at the degree of supersaturation present.
• Asphaltene solubility in crude oil is the thermodynamic basis of asphaltene deposition risk, with asphaltenes remaining stably dispersed (peptized) in the crude oil by resins at reservoir temperature and pressure conditions but potentially precipitating when the solubility parameter of the crude oil changes with pressure reduction (particularly through the bubble point), temperature change, or compositional changes from gas injection or CO2-EOR; the Flory-Huggins polymer solution theory and modified cubic equations of state (PC-SAFT equation of state) are used to calculate the asphaltene onset pressure — the reservoir pressure below which asphaltenes begin to precipitate from the oil — and the asphaltene envelope (the region of pressure-temperature-composition space within which asphaltenes are stable in solution); CO2 injection for EOR significantly reduces asphaltene solubility in many crude oils by lowering the resin-to-asphaltene ratio and changing the oil composition toward a less aromatic solvent, making asphaltene deposition management a critical flow assurance challenge in CO2-EOR projects in the Permian Basin, the Middle East, and Venezuela's Orinoco belt.