Partitioning

Key Takeaways

• Vapor-liquid equilibrium (VLE) and gas-oil partitioning govern the composition of the gas and liquid phases produced from a reservoir as a function of pressure and temperature, with equations of state (EOS) providing the thermodynamic framework for calculating the partition coefficients (K-values or equilibrium ratios) of each hydrocarbon component between the gas and liquid phases at specific pressure-temperature conditions: the K-value of a component (Ki = yi/xi, the ratio of its mole fraction in the vapor phase to its mole fraction in the liquid phase) is greater than 1 for light components (methane, ethane, propane) that preferentially partition into the gas phase, and less than 1 for heavy components (C7+ aromatics and naphthenics) that preferentially remain in the liquid phase; as reservoir pressure decreases below the bubble point during production, the light components partition progressively into the expanding gas phase (increasing the gas-oil ratio in producing wells) and the oil phase becomes progressively heavier and more viscous as its light component fraction is depleted; flash calculations using cubic equations of state (Peng-Robinson, Soave-Redlich-Kwong) compute the K-values for each component in a multicomponent mixture at specified pressure and temperature by iteratively solving the Rachford-Rice equation for the vapor fraction and the fugacity equilibrium conditions, providing the compositions of the equilibrium gas and liquid phases used in reservoir simulation, surface facility design, and pipeline hydraulics calculations.
• Partitioning in chemical EOR flooding (surfactant-polymer flooding) determines whether the injected surfactant forms the optimal microemulsion system that achieves ultra-low interfacial tension (IFT) with the reservoir crude oil, enabling mobilization of the residual oil saturation trapped in pore throats by capillary forces: the Winsor phase behavior of a surfactant-brine-oil system describes three types of microemulsion equilibrium — Type I (Winsor I, oil-in-water microemulsion in equilibrium with excess oil), Type II (Winsor II, water-in-oil microemulsion in equilibrium with excess water), and Type III (Winsor III, a middle-phase microemulsion in equilibrium with both excess oil and excess water); the Type III Winsor system corresponds to the optimal salinity condition where the surfactant partitions equally between the oil and water phases, forming a bicontinuous middle-phase microemulsion with ultra-low IFT (10^-3 to 10^-4 mN/m, compared to 20-30 mN/m for unmodified oil-water) that is required for capillary number mobilization of residual oil; the optimal salinity for the Winsor III system is determined by the structure of the surfactant (hydrophilic-lipophilic balance, HLB), the crude oil composition (characterized by the equivalent alkane carbon number, EACN), and the brine salinity; surfactant flooding design requires matching the optimal salinity of the surfactant system to the actual formation brine salinity, which may require co-surfactant addition (cosolvents that shift the optimal salinity) or salinity modification of the injected water.
• Tracer partitioning in reservoir surveillance uses tracers that partition selectively between the oil and water phases to measure the residual oil saturation in swept zones of a waterflood, providing information about flood efficiency that cannot be obtained from production performance data alone: interwell tracer tests inject a water-soluble tracer (such as tritiated water, radioactive iodide, or fluorinated organic compounds) and a partitioning tracer (a compound that partitions between the water and oil phases according to a known partition coefficient, such as hexanol or heptyl acetate) simultaneously into an injection well, then monitor their breakthrough at producing wells; the water-soluble tracer travels through the swept pore volume at the velocity of the water phase (unretarded by partitioning), while the partitioning tracer travels more slowly because it spends time in the residual oil phase (effectively being retarded by the factor 1 + Kow * (Sor/(1-Sor)), where Kow is the oil-water partition coefficient and Sor is the residual oil saturation); the ratio of the arrival times of the two tracers at the producing well gives the retardation factor, from which the residual oil saturation in the swept volume between the injection and production wells is calculated; single-well chemical tracer tests (SWCTT) inject a partitioning tracer that is subsequently produced back from the same well, using the retardation of the tracer in the near-wellbore swept volume to measure the local residual oil saturation at that well location; both test types provide direct in-situ measurements of Sor that are used to calibrate reservoir simulation models and to evaluate the effectiveness of EOR chemical flooding programs.
• Henry's Law partitioning governs the distribution of dissolved gases (CO2, H2S, methane, and other light hydrocarbons) between the aqueous phase and the gas or oil phase in multiphase petroleum systems, determining the concentration of these dissolved components in produced water and the rate of their release from produced water at surface conditions: Henry's Law states that the equilibrium partial pressure of a dissolved gas above a liquid is proportional to its concentration in the liquid (p = H * c, where p is the partial pressure, H is the Henry's Law constant, and c is the dissolved concentration), with the Henry's Law constant being temperature-dependent (increasing with temperature, so hot deep reservoir water holds more dissolved gas at reservoir conditions than the same water at surface conditions); when produced water is brought from high reservoir pressure and temperature to the low pressure and temperature of a surface separator, the reduction in dissolved gas solubility causes flash degassing of the water phase — releasing dissolved methane, CO2, H2S, and light hydrocarbons from the water into the vapor space; the volume and composition of the gas released from produced water during surface processing must be accounted for in separator design (to provide sufficient vapor handling capacity), in gas emissions calculations (methane emissions from produced water handling are a greenhouse gas reporting obligation under EPA regulations), and in H2S safety planning (H2S dissolved in produced water at reservoir conditions can be released in large quantities during surface handling, creating a safety hazard if vapor recovery and H2S detection are not properly designed for the degassed produced water stream).
• Petroleum biomarker partitioning between crude oil and water provides geochemical evidence for water washing, biodegradation, and the degree of water-oil contact that a petroleum accumulation has experienced during its geological history: water washing (the preferential dissolution of the more water-soluble aromatic hydrocarbons from crude oil into contacting formation water over geological time) depletes the crude oil of light aromatics (benzene, toluene, xylene — the BTEX compounds with the highest water solubility) while leaving the less water-soluble n-alkanes and biomarkers relatively unchanged, producing a characteristic pattern of BTEX depletion in water-washed crude that is measurable by GCMS analysis; the degree of water washing provides a proxy for the water-oil contact ratio experienced by the crude during its geological history (how many pore volumes of water have passed through the oil accumulation), which informs the paleohydrology of the petroleum system; biodegradation (microbial metabolism of crude oil components in shallow, low-temperature reservoirs where bacteria have access to the oil-water contact) selectively removes n-alkanes first, then branched alkanes, then polycyclic saturates, and finally the most resistant aromatic compounds and biomarkers, producing progressively degraded crude oil with increasing viscosity and decreasing API gravity; the Peters-Moldowan biodegradation scale quantifies the degree of microbial alteration from 0 (undegraded) to 10 (severely degraded) based on the progressive removal of these compound classes, providing a geochemical history of the crude that complements the geological information about reservoir depth and temperature history.