# Glossary

The following table attempts to summarize the most important terminology in the topics of PVT and black-oil modeling. The aim of this page is to give a brief description of the most common/important terminology and guide the reader to a more detailed description of the different topics at different locations.

Terminology & Short Description
API Specific Gravity: $$\gamma_{API}=(141.5/\gamma_o)-131.5$$, with units in °API. An alternative expression for surface oil specific gravity ($$\gamma_o$$), measured at 1 atm and 60°F. API stands for American Petroleum Institute.
Apparent Mass Density: The ratio of total mass of a mixture to the total mixture volume when the mixture exists as two (or more) phases. Sometimes the apparent mass density is provided in a PVT lab report for a CCE test at pressures below the saturation pressure where two (gas+oil) phases co-exist.
Binary Interaction Parameter (BIP): A correction term $$k_{ij}$$ for component pair i-j used in the “a” parameter mixing rule of a cubic EOS. $$k_{ij}=0$$ indicates no correction. A maximum range is usually $$k_{ij}\approx$$-0.1 to +0.2 for hydrocarbon-hydrocarbon pairs, $$k_{ij}\approx$$ 0.05 to 0.15 for hydrocarbon/non-hydrocarbon pairs (e.g. N2, CO2, H2S). BIPs are symmetric $$k_{ij}=k_{ji}$$, and $$k_{ii}=0$$. The BIP ($$k_{ij}$$) usually has a strong impact on K-values $$K_{i}$$ and $$K_{j}$$, but may impact the K-values of all components. BIPs can be temperature dependent. Binary interaction coefficient (BIC) is sometimes used instead of BIP.
Bubble Point: The state of a fluid mixture characterized by the co-existence of a liquid phase saturated with an infinitesimal quantity of equilibrium gas phase.
Bubble Point Pressure: The saturation pressure of a fluid mixture at its bubble point.
BTEX (BTX): BTEX refers to the aromatic hydrocarbons benzene, toluene, ethylbenzene and xylene. These compounds occur naturally in petroleum deposits. BTEX compounds are among the most abundantly produced chemicals in refining, with a wide variety of industrial applications. BTEX compounds have relatively high solubilities in water, and they are toxic.
Constant composition expansion (CCE): A PVT laboratory test of a fluid mixture where temperature is held constant, composition remains constant (no injection or removal from the PVT cell), and pressure is changed by altering the volume in the PVT cell. The CCE test (sometimes referred to as constant mass expansion or CME) is used to determine the saturation pressure, single-phase volume changes above the saturation pressure, and two-phase volume changes below the saturation pressure.
Composition: Quantifies the amount of each component in a fluid mixture, usually reported in mole or mass fraction. Gas chromatography and related analytical methods are used to determine the composition of gas and oil mixtures. Typical components quantified in petroleum mixtures include the nonhydrocarbons $$N_{2}$$, $$CO_{2}$$, and $$H_{2}S$$ and the hydrocarbons $$C_{1}$$, $$C_{2}$$, $$C_{3}$$, $$iC_{4}$$, $$nC_{4}$$, $$iC_{5}$$, $$nC_{5}$$ and $$C_{6}$$ with heavier compounds (heptanes-plus) that typically include many hundreds of compounds from the three families of hydrocarbons: paraffins (n-alkanes), naphthenes (cycloparaffins), and aromatics (containing benzene rings). $$H_2O$$ is almost always found in petroleum mixtures, though its content in gas and oil phases is seldom measured.
Condensate: A liquid resulting from condensation of a single-phase vapor. Condensate can result due to change in pressure and/or a change in temperature. At reservoir conditions (with constant temperature), “retrograde” condensate will develop when pressure is lowered below the upper dewpoint pressure of a reservoir gas mixture.
Convergence Pressure: The pressure of a fluid mixture at a given temperature where the K-values of all components appear to converge to unity when the isothermal ($$\log (K_i) - \log (p)$$) curves are extrapolated to pressures above the upper saturation pressure (i.e., into the undersaturated pressure region). The convergence pressure of a mixture can be calculated by an EOS using the negative flash, where the computed equilibrium compositions $$y_i$$ and $$x_i$$ are identical, fall on a tie line with the original mixture composition, and represent a composition $$z_{ci}=y_i=x_i$$ with critical pressure equal to the convergence pressure of $$z_i$$ at system temperature.
Cricondentherm: The maximum temperature at which liquid and vapor phases can coexist in equilibrium for a constant composition, multicomponent system.
Critical State: The state of a fluid mixture at which all properties of all coexisting vapor and liquid phases become identical (densities, viscosities, etc.), and the equilibrium ratios $$K_i=1$$ for all components. The mixture is called a saturated critical fluid at its critical state (not a saturated bubblepoint oil or a saturated dewpoint gas).
Critical Pressure: The saturation pressure of a fluid mixture at a critical state.
Critical Temperature: The saturation temperature of a fluid mixture at a critical state.
Constant volume depletion (CVD): A PVT laboratory test of a fluid mixture where temperature is held constant in a visual PVT cell, initially at saturation pressure, this defining the cell reference volume. Pressure is reduced in 5-10 stages by increasing the total cell volume at each new stage. At each stage, after pressure is reduced, gas volume is removed (maintaining constant pressure) until the cell volume returns to the original reference volume. The removed gas is quantified, as is the percent of cell (reference) volume that contains liquid condensate.
Dew Point: The state of a fluid mixture characterized by the co-existence of a vapor phase saturated with an infinitesimal quantity of equilibrium liquid (condensate) phase.
Dew Point Pressure: The saturation pressure of a fluid mixture at its dew point. All petroleum systems exhibit both lower (low-pressure) dewpoints, and higher-GOR fluids will usually exhibit upper (higher-pressure) dewpoints somewhere in the reservoir-to-surface temperature range.
Differential Liberation Expansion (DLE): A PVT laboratory test of an oil mixture where temperature is held constant in a PVT cell, initially at saturation pressure. Pressure is reduced in 5-10 stages by increasing the total cell volume at each new stage. At each stage, after pressure is reduced, gas volume is removed completely (maintaining constant pressure). The removed gas is quantified, and the remaining oil volume is measured. The final stage(s) of a DLE test may liberate a large gas volume that exceeds the maximum PVT cell volume. When this happens, gas is allowed to liberate while lowering the pressure, until reaching the maximum PVT cell volume. At this point, gas is bled from the cell (held at constant max volume) to continue lowering the pressure. This bleeding procedure is not documented in laboratory reports, and it can have a significant impact on the final resulting oil volume and properties. The bleeding process cannot be simulated by an EOS-based PVT model, where instead they typically simulate a simple flash to the final pressure(s), regardless of total cell volume limitations in the laboratory. The simulated flash will vaporize the oil more than seen in the laboratory, with a resulting too-low volume that impacts reported DLE properties $$B_{od}$$, $$R_{sd}$$, and final residual oil density.
Differential Process: A PVT laboratory process characterized by a constantly changing system (PVT cell) composition that is caused by stepwise differential pressure reductions below the initial system saturation pressure. After equilibrium is reached at each pressure reduction, some of the equilibrium gas is removed from the PVT cell. CVD (partial gas phase removal) and DLE (complete gas phase removal) are the two standard differential processes used in a conventional PVT laboratory study. The DLE differential process is far removed from the actual depletion process of a reservoir oil (where mainly oil and only some gas is produced). However, for many oils the DLE process yields reasonable estimates of phase properties (densities, viscosities, and oil shrinkage). The CVD differential process is very similar to the actual depletion process of all gas condensate reservoirs, where only reservoir gas phase is substantially mobile and produces.
Differential Gas Liberation: The laboratory PVT process whereby the composition of an oil system is changed by removing gas phase material. This term ordinarily refers to the consecutive removal of all gas phase that liberates from a saturated oil mixture during a DLE process. The cumulative differential gas volume removed during a DLE test causes, and is proportional with oil volume shrinkage. For volatile- and near-critical oil mixtures, the DLE removal of all liberated differential gas leads to a misleading (excessive) oil shrinkage compared with that is found in actual depletion, where only part of the differential gas is produced.
Dissolved Gas (Solution Gas): That material contained in a liquid phase at elevated pressure and temperature which, when brought to surface conditions (by a single- or multi-stage process), becomes a gaseous phase at atmospheric conditions.
Flash Calculation: An isothermal flash calculation is used to determine – based on total molar composition $$z_i$$, pressure and temperature – the number of phases that form, the moles of each phase, and the component mole fractions of each phase.
Flash Process: A process whereby a fluid mixture with known composition $$z_i$$ is brought to a pressure and temperature, thermodynamic equilibrium is reached, and the result is either a single (undersaturated) phase, or (at least) two equilibrium (saturated) phases. The flash process can be created physically in a laboratory, or it can be calculated from $$z_i$$ and $$K_i$$ using empirical K-value equations or an EOS model. Variables used to solve a two-phase vapor-liquid flash calculation include: $$f_V$$=vapor phase mole fraction defined as the moles of vapor phase divided by total moles, and K-values $$K_i=y_i/x_i$$ where $$y_i$$=vapor mole fractions and $$x_i$$=liquid mole fractions. The component material balance $$z_i=f_V \cdot y_i + (1-f_V) \cdot x_i$$ and constraint $$\sum (y_i-x_i)=0$$ are used to solve for $$f_V$$, $$y_i$$, and $$x_i$$. With $$z_i$$ known and $$K_i$$ estimated, a unique physical solution ($$y_i \geq 0$$, $$x_i \geq 0$$) will always exist if $$max (K_i) > 1$$ and $$min (K_i) < 1$$. Having solved the flash procedure above for $$y_i$$ and $$x_i$$, knowing pressure and temperature, an EOS model can be used to calculate the Gibbs equal chemical potential criteria for thermodynamic equilibrium, $$\mu_{iV}=\mu_{iL}$$, to be satisfied for all components. If not satisfied, new K-values are assumed, a new solution is found for $$f_V$$, $$y_i$$, and $$x_i$$, and the process is repeated until a set of $$K_i$$ leads to the satisfactory convergence of $$\mu_{iV}=\mu_{iL}$$ for all $$i$$.
Flash Gas Liberation: The formation of vapor from a liquid under conditions wherein the vapor and liquid phases remain in equilibrium.
Formation-Volume Factor (FVF): The volume of a single-phase fluid mixture at pressure and temperature (p,T), divided by a surface product volume resulting when the mixture is brought to surface conditions of 1 atm and 60°F through a single- or multi-stage process. Gas FVF is the ratio of single-phase gas volume at (p,T) to the resulting total surface gas volume. Oil FVF is the ratio of single-phase oil volume at (p,T) to the resulting total surface oil volume.The use of "formation" volume factor is by convention, where the term was originally used exclusively to convert reservoir formation phase volumes to surface product volumes. Today’s generic use of FVF does not require that the single-phase condition at (p,T) be conditions found in the reservoir formation; instead, it can be conditions within tubing or pipeline, or conditions at a primary separator.
Gas Gravity: The ratio of gas density at standard conditions (e.g., 1 atm and 60°F) to the density of air at the same standard conditions, i.e. a relative density. Assuming gas Z-factor of 1 at standard conditions (ideal gas law) for both gas and air, the gas specific gravity can be calculated from the ratio of gas molecular weight to air molecular weight (28.97).
Ideal Gas: An idealized gas conforming to the ideal gas law, pV=nRT, where p is absolute pressure, V is volume, n is the molar amount, T is absolute temperature, and R is the universal gas constant (appropriate for a specific set of units). An ideal gas assumes a “deviation” factor Z=1
Incipient Phase: A mixture at pressure and temperature that is on a phase boundary (dewpoint or bubblepoint) will form a new phase, infinitesimal in size, that is in thermodynamic equilibrium with the main phase. The newly formed infinitesimal phase is referred to as an incipient phase. The main phase is saturated with the incipient phase, and vice versa.
Injection Gas: Gas injected into a reservoir. Injection gas usually consists of partially- to fully-processed, hydrocarbon-rich production gas. A lean injection gas would be fully-dried from water and almost all hydrocarbons heavier than propane. Separator injection gas (with little drying & additional processing) will contain components out to $$C_{7}$$-$$C_{10}$$, but with only minor (<1 mol-%) amounts of $$C_{6+}$$. Other injection gases include $$C_{2}$$, $$N_{2}$$, and flue gas mixtures with significant amounts of both non-hydrocarbons. Injection gas will partially dissolve into reservoir fluids (oil, gas condensate and water), immiscibly displace reservoir fluids, and with sufficient pressure may develop highly efficient, near-miscible recovery of the entire reservoir fluid system. In all cases, a significant percentage of injection gas will remain as a gas phase within the reservoir, providing important pressure maintenance support.
K-values (Equilibrium Ratios): $$K_i$$≡$$y_i$$/$$x_i$$ where $$y_i$$=equilibrium vapor phase mole fraction of component i, and $$x_i$$=equilibrium liquid phase mole fraction of component i, where i=1,…,N with N total components in the total fluid mixture of composition $$z_i$$. $$K_i$$ are a function of pressure, temperature, and total composition $$z_i$$. $$K_i$$>1 implies that component i has a relative preference to partition into the vapor phase, and $$K_i$$<1 implies that component i has a relative preference to partition into the liquid phase. $$K_i$$=1 at a critical point and at low pressures where component i behaves (approximately) as if it exists and behaves as a pure compound at its vapor pressure.The K-values are used together with $$z_i$$ to solve phase equilibrium calculations with an EOS. The K-values control amounts of vapor and liquid phases, and the molar composition of each equilibrium phase – thereby mapping the p-T and p-z phase envelopes of p-T-z space that is single- and two-phase. For 2-constant (a,b) cubic EOSs with zero BIPs, the exact expression for K-values is $$\ln (K_i) = C_0 + C_1 \cdot \sqrt{a_i} + C_2\cdot b_i$$, where constants $$C$$ are a function of pressure, temperature, and composition.
Liquid: A fluid phase label of a mixture at pressure and temperature, usually based on an arbitrary bulk property such as viscosity (e.g. > 0.1 cp). A saturated liquid is, by definition, in thermodynamic equilibrium with one or more fluid phases, being “saturated” with the equilibrium phase(s). In petroleum reservoir fluid definitions, a (liquid) “oil” reservoir fluid is defined formally as a hydrocarbon fluid mixture that exhibits a bubble point at reservoir temperature. Using this definition, the reservoir liquid is saturated oil at its bubble point, and undersaturated oil at pressures greater than the bubblepoint pressure.
Liquid Saturation: The extent to which pores in a reservoir rock are filled with liquid. Saturation ordinarily is expressed as a per cent of pore volume.
Liquid Specific Gravity: The ratio of density of any liquid measured at standard conditions (usually 14.7 psia and 60°F) to the density of pure water at the same standard conditions. Denoted mathematically as $$\gamma_o$$ (where water= 1).
Mass Composition: Mass fraction (or weight fraction) of component i in a mixture or phase, $$w_i$$=$$m_i$$/$$m$$ (m=mass).
Mass Density: The ratio of mass to volume for a phase.
Mixing Rules: For mixtures with known molar or mass composition, average properties are inevitably needed for direct use (e.g. average molecular weight), or indirectly to estimate parameters that are used in correlations (e.g. gas specific gravity), corresponding states methods (e.g. $$T_{pc}$$, $$p_{pc}$$), and generalized equations of state (a,b). Averaged properties $$\theta_{\mathrm{avg}}$$ are usually estimated from the mixture molar composition $$z_i$$ and individual-component physical properties $$\theta_i$$ ($$p_c$$, $$T_c$$, $$V_c$$, $$T_b$$, acentric factor $$\omega_i$$, Parachor P, etc.). The simplest mixing rule is a linear molar mixing rule, sometimes called Kay’s mixing rule, $$\theta_{\mathrm{avg}}= \sum z_i \cdot \theta_i$$ most used when estimating pseudocritical properties. Some mixing rules are found empirically to best correlate average properties, while many non-linear mixing rules are founded on a theoretical basis such as the quadratic mixing rule (proposed by van der Waals) for the attractive parameter a in cubic EOS models.
Mixture: A collection of components. A pure compound is a trivial mixture for molecules of a single species.
Molar Composition: Mole fraction of component i in a mixture or phase: $$z_i$$=$$n_{it}$$/$$n_t$$ = total mixture molar composition, $$y_i$$=$$n_{iV}$$/$$n_V$$ = vapor phase molar composition, and $$x_i$$=$$n_{iL}$$/$$n_L$$ = liquid phase molar composition (n=moles).
Molar Density: The ratio of moles to volume for a phase.
Molar Units: The SI unit of molar amount is mol. This represents the mass in grams of 6.02214086x10$$^{23}$$ molecules (Avogadro’s number) of any substance. It is common to use molar quantity “units” other than that based on grams. For example, if you have 1 kg of a substance, the molar quantity is referred to as 1 kg mol (or 1 kg-mole). Formally, in SI units, one could write this quantity as 1 kmol, referring to the fact that kg = 1000 grams. Thus, 1 kmol has 6.02214086×10$$^{23}$$ x 1000 = 6.02214086×10$$^{26}$$ molecules. If our preferred mass unit is pound mass, $$lb_m$$ (or just $$lb$$), then our preferred molar quantities might be given in $$lb_m$$ mol (“lb-mole”). The conversion from lb-mole to $$lb$$ mass is trivial, =1 lb/lb-mole. The conversion from lb-mole to mol (using g as the mass unit) uses the same conversion factor as converting $$lb_m$$ to g – 453.6 $$\frac{g}{lb_m}$$ = 453.6 mol/lb-mole. Thus, 1 lb-mole has 453.6 x 6.02214086×10$$^{23}$$ molecules. Sometimes you will see the formal SI unit mol written as (an unofficial equivalent) g-mole, with trivial conversion 1 g/g = 1 mol/g-mole.
Negative Flash: The flash calculation is performed with $$z_i$$, p and T specified, but the converged EOS-based solution leads to $$f_V<0$$ or $$f_V>1$$, i.e., a negative phase amount for one of the two equilibrium phases. Although this solution tells us that $$z_{i}$$ is physically a single phase at the specified pressure and temperature, it generates two phases yi and xi that are in thermodynamic equilibrium ($$\mu_{iV}=\mu_{iL}$$). The two equilibrium phases lie on a tie line that intersects total composition $$z_i$$. The negative flash solution corresponds to a saddle point instead of a minimum in Gibbs total energy (for $$0 \geq f_V \geq 1$$). As $$f_{V}$$ approaches ±∞ from a negative flash calculation, the resulting equilibrium phases approach one another $$y_i=x_i=z_{Ki} \neq z_i$$, and $$K_i=1$$. At such a condition, the specified pressure of the system is a critical pressure of the calculated equilibrium composition $$z_{Ki}$$ at the specified temperature, and a critical tie line passes through $$z_{i}$$ and $$z_{Ki}$$. We call this condition a convergence pressure of $$z_{i}$$ at the specified temperature.
Permeability: A measure of the capacity of a porous material to transmit fluid. The unit of permeability is the darcy. A material has the permeability of one darcy when one atmosphere pressure differential across one centimeter length causes a viscous flow of one cubic centimeter per second of a fluid of one centipose viscosity through a cross section of one square centimeter.
Phase: A mixture at pressure and temperature where the bulk physical (intensive) properties, like density and viscosity, and composition are tending towards spatially homogeneity. At equilibrium, a phase has achieved spatial homogeneity of component total energy, bulk intensive properties, and composition.
Phase Behavior: Within the petroleum domain, phase behavior describes how fluid and some solid phases behave in terms of intensive and extensive property variations as a function of pressure, temperature, volume, and composition. For a given mixture of components, the phase behavior at a specific pressure and temperature will encompass how many phases form, in what amounts, how the individual components partition amongst the equilibrium phases, and the physical properties of each phase (e.g. density and viscosity).
Phase Transition (Boundary): Mapping the phase behavior of a petroleum mixture involves defining the boundaries between saturated and undersaturated states in terms of pressure, temperature, and composition. The transition from saturated-to-undersaturated state is referred to as a phase boundary, where the mapping of phase boundaries is used to create phase diagrams (p-T, p-x).
Production: The material which is produced in liquid and /or gaseous phases at the well head.
Production Gas-Oil Ratio: The ratio of natural gas production rate to crude oil production rate, expressed as cubic feet per barrel measured under standard conditions.
Properties (Extensive and Intensive): Intensive properties are independent of the quantity of material, and describe any amount of a mixture or phase at a particular state of pressure and temperature. Example intensive properties include density, viscosity, and saturation pressure. Extensive properties depend on the amount of material making up the system (e.g. mass, volume, energy).
Pseudo-critical Properties: Non-physical mixture properties such as pressure, temperature and volume that are used to estimate reduced (or pseudoreduced) properties provided by corresponding states methods to estimate mixture properties such as Z-factor. An example is the Standing-Katz correlation for real gases: $$Z_g=f(T_{pr}, p_{pr})$$ using pseudocritical temperature $$T_{pr}=T/T_{pc}$$ and pseudocritical pressure $$p_{pr}=p/p_{pc}$$. Pseudocritical properties $$\theta_{pc}$$ are usually estimated from the mixture molar composition $$z_i$$ and individual component physical critical properties $$\theta_{ci}$$. Most pseudocritical mixing rules simplify to Kay’s mixing rule $$\theta_{pc}=\sum_i z_i \cdot \theta_{ci}$$ in certain limiting conditions.
PVT: An abbreviation of pressure, volume and temperature and typically refers to the study of how hydrocarbon systems behave with respect to pressure, temperature, volume and composition.
Reduced Properties: The ratio of a system’s pressure, temperature or volume to the critical (or pseudocritical) pressure, temperature, or volume of the system, respectively: $$p_{pr}=p/p_{pc}$$, $$T_{pr}=T/T_{pc}$$, $$V_{pr}=V/V_{pc}$$. Reduced (or pseudoreduced) properties are required by corresponding states methods to estimate mixture properties such as Z-factor. An example is the Standing-Katz correlation for real gases: $$Z_g=f(T_{pr}, p_{pr})$$.
Reservoir Rock: Any rock which contains a commercially exploitable concentration of hydrocarbons.
Residual Oil: The hydrocarbon liquid remaining in a PVT cell at the completion of a differential process conducted at or near the reservoir temperature. Also, the hydrocarbon liquid remaining in a reservoir at the end of a recovery process such as depletion, water- or gas injection.
Saturated Fluid (Phase): A fluid phase that is in thermodynamic equilibrium with one or more other phases at a given pressure and temperature. The phase in question is “saturated” with all of the other equilibrium phases. Examples of saturated phases include: (1) gas and oil at an initial gas-oil contact (GOC) where the GOC gas dewpoint equals the GOC oil bubblepoint equals the GOC pressure, (2) hydrocarbon gas and oil phases in a pore with an aqueous phase, and (3) gas, oil, and water flowing in a separator. Salts like NaCl will dissolve partially or completely in oilfield brines, but salts are assumed not to equilibrate and partition into non-aqueous (gas and oil) phases.
Saturated Liquid: A liquid that is in equilibrium with a vapor phase (and/or other liquid phases) at a given pressure and temperature.
Saturated Vapor: A vapor that is in equilibrium with one or more liquid phases at a given pressure and temperature.
Saturation Pressure: For a mixture at given temperature, the pressure at which a new infinitesimal (“incipient”) phase appears upon slight change in pressure. The mixture and its incipient phase are in thermodynamic equilibrium. If the incipient phase is lighter than the mixture phase, the saturation pressure is a bubblepoint and the incipient phase is a bubble appearing from the oil mixture. If the incipient phase is heavier than the mixture phase, the saturation pressure is a dewpoint and the incipient phase is a liquid (“dew”) appearing from the gas mixture. Petroleum mixtures will always exhibit lower dewpoints for the entire range of temperatures exhibiting two phases (i.e. less than the cricondentherm), while upper saturation pressures of both bubblepoint and dewpoint type are usually found in the range of relevant operational temperatures.
Shrinkage: The decrease in single-phase oil volume at a given pressure and temperature ($$p_1$$,$$T_1$$) when brought to another condition ($$p_2$$,$$T_2$$). See shrinkage factor.
Shrinkage Factor: The percentage decrease in single-phase oil volume $$V_{o1}$$ at a given pressure and temperature ($$p_1$$,$$T_1$$) when brought to another condition ($$p_2$$,$$T_2$$) with resulting oil volume $$V_{o2}$$. Shrinkage factor (SF) is calculated as $$SF=(V_{o2} - V_{o1})/V_{o1}$$, expressed in percentage. The oil volume change is, in most cases, caused mainly by the release of solution gas; thermal contraction or expansion will also impact the shrinkage factor. The process path from ($$p_1$$,$$T_1$$) to ($$p_2$$,$$T_2$$) may involve any number of complex stages of equilibrium and non-equilibrium conditions, and will have an impact on the shrinkage factor. If standard conditions represent the final ($$p_2$$,$$T_2$$) conditions, the shrinkage factor is related to oil volume factor as $$SF=1-(1/B_{o})$$, or $$B_{o}=1/(1-SF)$$, where SF is given as a fraction. Consider $$V_{o1}$$=1000 bbl of a separator oil at $$p_2$$=1000 psia and $$T_1$$=100°F yields 750 STB (stock-tank barrels) at $$p_2$$=14.7 psia and $$T_2$$=60°F. The separator oil shrinkage factor is then 25%=(1000-750)/1000, for a particular process path from ($$p_1$$,$$T_1$$) to ($$p_2$$,$$T_2$$). Other process paths might lead to lower or higher shrinkage factors (e.g. 15 to 30%). For SF=0.25, $$B_{osp}$$=1/(1-0.25)=1.33 separator barrels per STB.
Solution (In-Situ) Gas-Oil Ratio: The volume ratio of total surface gas to the surface oil of an in situ reservoir fluid, when brought to surface conditions of 1 atm and 60°F through a single- or multi-stage process.
Solution Gas Drive: A primary oil depletion recovery process whereby oil is displaced from the reservoir rock by the expansion of liberated solution gas that was originally dissolved in the oil phase.
Solution Gas-Oil Ratio: The volume ratio obtained by taking the moles of total gas that is liberated from a single-phase liquid undergoing a surface separation process. Liberated moles of gas are converted to ideal gas volumes), and then divided by the resulting stock-tank oil at standard conditions.
Stabilized Crude Oil: A processed oil that is fully stabilized at standard conditions, or conditions of (near-atmospheric) transportation. A stabilized crude oil should reduce volatile organic compound (VOC) losses during storage and transportation.
Stock Tank Oil: The final surface oil product when a hydrocarbon mixture undergoes a surface separation process that terminates at atmospheric pressure. The stock-tank volume and properties will always be reported at 1 atm and 60°F. Other terms for stock tank oil include “crude”, “crude oil”, “surface oil”, “tank oil”, and “processed oil”.
Surface Condensate (Distillate): A surface hydrocarbon liquid (stock-tank sales product) resulting from the surface processing of a reservoir gas. Usually, multiple stages of separation result in surface condensate.
Surface Gas Volume: Natural gases at ambient conditions of 1 atm and T~60°F are usually assumed to be described as an ideal gas. An exact conversion of gas moles to gas volume at standard conditions (1 atm and 60°F) using the ideal gas law is an industry practice for representing gas quantity on a “surface” volumetric basis. Units of surface gas volumes are commonly scf (standard cubic feet) and std m$$^3$$ or Sm$$^3$$ (standard cubic meters), with surface gas volume conversion factors of 379.4 scf/lbm mol and 23.69 Sm$$^3$$/kmol.
Systems, Homogeneous and Heterogeneous: A body of matter with finite boundaries that represents the material under consideration. In a homogeneous system the intensive properties like density vary only slightly and in a continuous manner with respect to the extent of the system. A heterogeneous system (a) is made up of a number of homogeneous parts, with abrupt changes in the intensive properties at the surface of contact between homogeneous parts of the system, or (b) exhibits continuous but significant spatial variations of intensive properties that, given sufficient time, will ultimately become homogeneous via various mechanisms of transport.
Undersaturated Fluid (Phase): A liquid or vapor phase that is single phase at a given pressure and temperature, not in equilibrium with any other fluid phase(s). The (p,T) condition is outside the saturated boundary of the fluid’s phase p-T diagram. The term undersaturated implies that the fluid is less than saturated with some other fluid. That “other” fluid is usually the incipient phase that appears when moving from (p,T) to the fluid’s saturated phase boundary (bubblepoint or dewpoint). Undersaturated can also, in some instances, refer to an oil that is undersaturated with respect to an injection gas.
Universal Gas Constant (R): A numerical constant used in equations of state, such as the ideal gas law pV=nRT. R=10.7315 psi⋅ft$$^3$$/lb-mole⋅°R for field units; R=8.3145 m3⋅Pa/K⋅mol for SI units. Derived from Avogradro’s number and the Boltzmann constant, with 2019 “exact” re-definition by SI as R=8.31446261815324 m3⋅Pa/K⋅mol.
Vapor (Gas): A fluid phase label of a mixture at pressure and temperature, usually based on an arbitrary bulk property such as viscosity (e.g. < 0.1 cp). A saturated vapor is, by definition, in thermodynamic equilibrium with one or more fluid (usually liquid) phases, being “saturated” with the equilibrium phase(s). In petroleum reservoir fluid definitions, a “gas” reservoir fluid is defined formally as a hydrocarbon fluid mixture that exhibits an upper dew point at reservoir temperature. Using this definition, the reservoir gas is saturated gas at its dew point, and undersaturated gas at pressures greater than the upper dewpoint pressure.
Vapor Pressure: For a compound at a temperature below the critical temperature ($$T_c$$), down to the triple point $$T_t$$, and further down to 0 degrees absolute ($$T_0$$), the vapor pressure defines where the compound exists in a multi-phase thermodynamic equilibrium with (a) saturated vapor and saturated liquid ($$T_t<T<T_c$$), (b) saturated vapor and saturated solid ($$0<T<T_t$$), or (c) saturated vapor, saturated liquid, and saturated solid ($$T=T_t$$). The collection of vapor pressures is called the vapor pressure curve. As temperature increases from the triple point to the critical point, the difference in equilibrium phase properties will decrease monotonically until the phase properties show no difference, and the two phases become identical at the critical point. The Gibbs chemical energy (or fugacities) of saturated phases at the vapor pressure for a given temperature will always be equal, independent of the amount of each equilibrium phase. The system volume will determine how much of each equilibrium phase exists. For a temperature on the saturated vapor-liquid curve ($$T_t<T<T_c$$)), the volume changes from its minimum value with 100% saturated liquid to a maximum value with 100% saturated vapor. The pressure will remain completely constant, equal to the vapor pressure, as volume changes from 100% saturated liquid to 100% saturated vapor. A plot of volume versus pressure will, therefore, lead to a horizontal shock line connecting the minimum and maximum saturated volumes. Interestingly, no equation of state functional form reproduces this fundamental (horizontal shock) pressure-volume behavior for any point on the vapor pressure curve (except at the critical point). Not even the behavior of a propane bottle as it empties during your grilling experience!
Volatile Organic Compounds (VOC): Light hydrocarbon components from methane through decane (<$$C_{15}$$), including aromatic BTEX compounds that can be released from crude oil during storage and transportation. VOC losses to the atmosphere are mainly due to interaction of the crude oil with the surrounding atmospheric vapor (air, nitrogen, hydrocarbons), where thermodynamic equilibrium partially vaporizes the crude oil under the influence of changes in temperature, pressure, and surrounding-gas composition. VOC is defined by the US Environmental Protection Agency (EPA) as any compound of carbon, excluding carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, and ammonium carbonate, which participates in atmospheric photochemical reactions.
Watson Characterization Factor (UOPK): A characterization factor $$K_w≡T_b^{1/3}/\gamma$$, where normal boiling point Tb is given in °R, and $$\gamma$$ is the liquid specific gravity at 1 atm and 60°F. The Watson characterization factor is low (8-9) for aromatic compounds and high (12-13) for n-alkane or paraffin compounds. $$K_w$$ can be used for pure compounds or mixtures that exist as a liquid at 1 atm and 60°F (i.e. with a normal boiling point >60°F). The Watson factor of a surface oil mixture, distillation cuts, or heptanes-plus fractions will indicate an average relative paraffinicity / aromaticity, typically $$K_w=11.5 \to 12.2$$ for most surface oils worldwide, with “low” (<11) values for aromatic oils, and “high” (>12.5) values for paraffinic oils. Watson worked for Universal Oil Products when he proposed this characterization factor in 1935, and it is often referred to as UOPK or UOP K.
Z-factor: Z≡pV/(nRT), a dimensionless variable. Most commonly used to express the deviation of gas volumetric behavior from that of ideal gas. Also used in EOS calculations to solve for the volume of all (gas and liquid) phases. Various names are used for the Z-factor, including the most common, “gas deviation factor” (from ideal gas behavior).