Natural gas properties

Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N₂), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. This article discusses phase behavior, pressure volume temperature (PVT) behavior, gas density and formation volume factor (FVF), viscosity, determining reservoir fluid properties, retrograde behavior, and equations of state (EOS).

Contents

• 1 Types of gas reservoirs
• 2 Phase behavior of natural gas reservoirs
• 3 Pressure/volume/temperature (PVT) behavior
• 4 Gas density and formation volume factor
• 5 Viscosity
• 6 Determining reservoir-fluid properties
• 7 Measuring retrograde behavior
• 8 Equations of state
  • 8.1 Ideal gas
  • 8.2 van der Waals
  • 8.3 Soave-Redlich-Kwong
  • 8.4 Peng-Robinson

  Types of gas reservoirs

  A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life. Condensate will form either while flowing to the surface or in lease-separation equipment. A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases (condensate and gas) in the reservoir when the reservoir pressure decreases. Additional condensate forms with changes in pressure and temperature in the tubing and during lease separation. From a reservoir standpoint, dry and wet gas can be treated similarly in terms of producing characteristics, pressure behavior, and recovery potential. Wellbore hydraulics may be different. Studies of retrograde-condensate gas reservoirs must consider changes in condensate yield as reservoir pressure declines, the potential for decreased well deliverability as liquid saturations increase near the wellbore, and the effects of two-phase flow on wellbore hydraulics.

  Phase behavior of natural gas reservoirs

  A widely accepted system for categorizing petroleum reservoir fluids is based on five classes:

  • Low-shrinkage (crude) oils
  • High-shrinkage (volatile) oils
  • Retrograde-condensate gases
  • Wet gases
  • Dry gases

  Typical phase diagrams for the gas categories are shown in Figs. 1 through 3.

  

  Fig. 1 – Phase diagram of a retrograde-condensate gas. [1] (Source: The Properties of Petroleum Fluids, second edition, by William D. McCain Jr. Copyright Pennwell Books, 1990.)

  

  Fig. 2 – Phase diagram of a wet gas. [1] (Source: The Properties of Petroleum Fluids, second edition, by William D. McCain Jr. Copyright Pennwell Books, 1990.)

  

  Fig. 3 – Phase diagram of a dry gas. [1] (Source: The Properties of Petroleum Fluids, second edition, by William D. McCain Jr. Copyright Pennwell Books, 1990.)

  A retrograde-condensate fluid has a phase envelope such that reservoir temperature lies between the critical temperature and the cricondentherm (Fig. 1). As a result, a liquid phase will form in the reservoir as pressure declines, and the amount and gravity of produced liquids will change with time. Condensate liquids are generally "water white" or light in color (brown, orange, or greenish), with gravities typically between 40 and 60°API. Producing-liquid yields can be as high as 300 STB/MMscf. McCain [1] suggests that when yields are below approximately 20 STB/MMscf, even though phase-behavior considerations may show retrograde behavior, the amount of liquid dropout in the reservoir is insignificant. The primary difficulties in producing condensate reservoirs are as follows:

  • Liquid deposition near the wellbore causes a decrease in gas deliverability that can approach 100% in a reservoir with less than 50-md permeability
  • A large amount of the most valuable hydrocarbon components is left in the reservoir rather than produced

  In a wet-gas reservoir, temperature is higher than the cricondentherm (Fig. 2). Therefore, a liquid phase never forms in the reservoir. Considerable liquid can still form (condense) at surface conditions or even in the wellbore. The term "condensate" is often applied to any light hydrocarbon liquid produced from a gas well. However, the term "condensate reservoir" should be applied only to situations in which condensate is actually formed in the reservoir because of retrograde behavior. Wet-gas reservoirs can always be treated as containing single-phase gas in the reservoir, while retrograde-condensate reservoirs may not. Wet-gas reservoirs generally produce liquids with gravities similar to those for retrograde condensates, but with yields less than approximately 20 STB/MMscf. [1]

  In a dry-gas reservoir, the cricondentherm is much lower than the reservoir temperature (Fig. 3), resulting in little or no liquid production at the surface. A somewhat arbitrary cutoff liquid yield of 10 STB/MMscf is sometimes used to distinguish dry-gas reservoirs.

  While the difference between retrograde-condensate and wet gases is notable, there is much less distinction between wet and dry gases. For both wet and dry gases, reservoir engineering calculations are based on a single-phase reservoir gas. The only issue is whether there is a sufficient volume of produced liquid to be considered in such calculations as material balance or wellbore hydraulics. Retrograde systems require more-complex calculations using equations of state (EOSs) and other advanced engineering methods.

  Pressure/volume/temperature (PVT) behavior

  The basis of gas PVT behavior is the ideal gas law, and by extension the real gas law:

  The universal gas constant in practical units is

  

  For economic reasons, most (but not all) pressure gauges read zero pressure when pressure is equal to the ambient atmospheric pressure. Therefore, atmospheric pressure must be added to gauge pressures to convert them to an absolute basis. For most engineering purposes, atmospheric pressure is usually taken to be 14.7 psia (101 kPa). For precise scientific and engineering applications, actual atmospheric pressure (i.e., barometric pressure, which varies with both location and time) should be used. Standard temperature and pressure are set by different governmental agencies and should be determined for a specific field or reservoir to be sure that reserves and produced quantities are reported with the correct bases. The SPE standard temperature is 59°F (15°C), and the standard pressure is 14.696 psia (101.325 kPa).

  Application of Eq. 1, in a practical sense, must consider how to determine the various factors for petroleum gases that are mixtures of several components. Such determinations would include apparent molecular weight and z (using pseudoreduced pressure and temperature and corrections for nonhydrocarbon components).

  Gas density and formation volume factor

  The density of a gas can be calculated from the real-gas law once a z factor has been determined. For pressure in psia and temperature in °R, density in lbm/ft 3 is given by

  For pressure in kPa, temperature in K, and density in kg/m 3 ,

  The gas formation volume factor is defined as the volume occupied by a gas at reservoir conditions divided by the volume at standard conditions:

  The second and third lines of Eq. 5 give B_g using standard pressure of 14.696 psia and standard temperature of 60°F.

  In SI units using SPE standard pressure and temperature,

  Viscosity

  Most gas viscosities range from 0.01 to 0.03 cp, making them difficult to measure accurately. Accurate determination of gas viscosities has low economic value. Instead, values are normally determined from one of two correlations.

  The first one in common use today, from Lee et al., [2] is given in equation form as

  where , and

  The gas density in Eq. 7 is in g/cm 3 when p and T are in oilfield units (psia, °R). The equivalent formula for SI units (pressure and temperature in kPa and K, respectively) is

  Fig. 4 shows gas viscosities generated from this correlation for a 0.80-gravity natural gas.

  

  Fig. 4 – Viscosity of 0.80-gravity natural gas vs. pressure and temperature according to the Lee et al. [2] correlation.

  Another common correlation [3] entails a two-step graphical process and is cumbersome for computer applications. Because gas viscosities are seldom needed with great accuracy, the Lee et al. [2] correlation is most applicable for modern reservoir-engineering practice.

  Determining reservoir-fluid properties

  Condensation of liquids from wet-gas and retrograde-condensate fluids in the production system means that gas produced from separation equipment may be significantly different from the gas that flows into the wellbore from the reservoir. In general, separator gas will be lower in gravity and will have fewer high-molecular-weight hydrocarbons present in the mixture.

  For proper laboratory measurements, a bottomhole sample should be collected. An alternative is a reconstituted sample that is created by mixing the separator-produced gas and liquid in proportion to their relative production rates. When the compositions of liquid and gaseous streams have both been measured, the composition of the mixture can be determined from

  Relative molar amounts can be determined by converting measured produced volumes either to moles or to equivalent standard cubic feet. For a gas phase, conversion of a produced volume referenced to standard conditions to moles is

  For a liquid, conversion of a volume to moles is

  If liquid volume is measured at standard conditions, density can be calculated from specific gravity or API gravity. If liquid molecular weight is not measured, it can be approximated with the Gold et al. [4] correlation:

  An alternative to converting measured volumes to moles is to convert all measured volumes to equivalent standard volumes because standard volume is directly proportional to moles (through the value of the standard molar volume). This procedure has the advantage that measured gas volumes need not be converted (this is necessary only for liquid volumes).

  Liquid volumes are converted to equivalent gas standard volumes using a parameter called the gas equivalent of oil. This parameter represents the effective standard volume occupied by hydrocarbons that are liquid at surface conditions but are in the gas phase at downhole conditions. This parameter is calculated by

  GE_o is calculated with oilfield units in Mscf/STB (the second term below uses standard conditions of 14.696 psia and 60°F) by

  In SI units, GE_o in std m 3 /std m 3 is (using standard conditions of 101.325 kPa and 15°C)

  Liquid-production volumes are multiplied by GE_o to determine the equivalent standard volume as gas in the reservoir; that is,

  where is the actual oil volume measured at stock-tank conditions, and is the gas-equivalent volume of the oil.

  These equations also can be used to determine the equivalent gas production of pure hydrocarbons separated from gas in a processing plant. Values of specific gravity and molecular weight for pure components can be found from standard sources such as the Gas Processors Suppliers Association (GPSA) Handbook. [5] In addition, if liquid production is measured at separator, rather than stock-tank, conditions, Eq. 16 or Eq. 17 can be used with separator temperature and pressure rather than standard temperature and pressure.

  Relative volumes of gas and liquid phases can then be calculated as

  When wellstream composition is unavailable, correlations must be used to determine gas properties, requiring the calculation of the wellstream (mixture) gravity on the basis of the gravity of the separator gas (often called dry gas) and the specific gravity of the produced liquid (condensate or oil):

  where the subscript g refers to the separator-gas gravity, wg refers to the wellstream gas, and o refers to the produced condensate (oil). Y is the produced condensate yield. Gold’s correlation can be used to estimate condensate molecular weight.

  In oilfield units with yield in STB/MMscf,

  In SI units with yield in std m 3 /std m 3 ,

  

  . (10.22)

  Measuring retrograde behavior

  When a liquid phase begins to form in the reservoir, the produced stream is no longer representative of the reservoir-fluid composition, but rather only the composition of the fluids entering the wellbore. Situations in which the liquid content of gases is high require the use of advanced laboratory tests and/or equation-of-state modeling to measure and predict these multiphase effects.

  Laboratory measurements of the PVT behavior of condensate systems are similar to tests used for black oils; however, the primary interest becomes the measurement of relatively small amounts of condensed liquid. In general, systems with producing gas/oil ratios of 15,000 scf/STB (67 STB/scf) have a liquid dropout of approximately 4 to 6% by volume, while reservoirs with ratios around 50,000 scf/STB ordinarily have liquid dropouts of less than 1% by volume. [1]

  Two types of tests are generally run on retrograde fluids: constant-composition expansion (CCE) and constant-volume depletion. For examples refer to Tables 1 through 3.

  

  Table 1 - Example field and analysis data for retrograde-fluid study. [6] Table 2 - Example volumetric behavior of condensate well fluid. [6]

  

  Table 3 - Depletion study at 256°F.

  Table 1 [6] gives the compositions of separator gas and liquid streams and other data used in making a recombined sample for analysis of reservoir-fluid composition.

  A CCE using a visual cell furnishes the dewpoint of the reservoir fluid at reservoir temperature and the total volume of the reservoir fluid as a function of pressure. The volume of liquid formed at pressures below the dewpoint can also be measured. Table 2 [6] shows the results of such a test. The term "relative volume" refers to the volume of gas plus liquid compared to the dewpoint volume. Retrograde-liquid volume is given as a percent of pore space, which essentially shows how the average condensate saturation changes with average reservoir pressure. Fig. 5 is a graphical representation of the relative condensate volume.

  

  Fig. 5 – Example retrograde-liquid volume vs. pressure. [6]

  Visual cells also can be used to simulate pressure depletion. The validity of these tests is based on the assumption that the retrograde liquid that condenses in the reservoir will not be mobile. This assumption is valid except for very rich gas/condensate reservoirs. If significant retrograde liquid becomes mobile and migrates to producing wells, gas/liquid relative permeability data should be measured and used to adjust the predicted recovery.

  Table 3 is an example of a visual-cell depletion study on the same retrograde gas for which properties are shown in Tables 1 and 2.

  The depletion study begins by expanding the reservoir fluid in the cell until the first depletion pressure is reached (5,000 psig in this example). The fluid in the cell is brought to equilibrium, and the volume of retrograde liquid is observed. Gas is removed from the top of the cell while a constant pressure is maintained until the hydrocarbon volume of the cell is the same as when the test began. The gas volume removed is measured at the depletion pressure and reservoir temperature, analyzed for composition, and measured at atmospheric pressure and temperature.

  The ideal-gas law can be used to calculate the "ideal volume" at the depletion pressure and reservoir temperature of the gas withdrawn from the cell. Dividing the ideal volume by the actual volume yields the deviation factor, z, for the produced gas. This is listed in Table 4 under z for the equilibrium gas. The actual volume of gas remaining in the cell at this point is the gas originally in the cell at the dewpoint pressure minus the gas produced at the first depletion level. Dividing the actual volume remaining in the cell into the calculated ideal volume remaining in the cell at this first depletion pressure yields the two-phase deviation factor shown. The two-phase z factor is an equivalent z factor that includes the total volume of gas plus liquid:

  The two-phase z factor is the correct value to apply to such things as p/z analysis of retrograde-condensate reservoirs.

  

  Table 4 - Definitions of a "generic" potential difference Δ_Ψ for different fluids.

  A series of expansions and constant-pressure displacements is repeated at each depletion pressure until an arbitrary abandonment pressure is reached. The abandonment pressure is considered arbitrary because no engineering or economic calculations have been made to determine this pressure for the purpose of the reservoir-fluid study.

  At the final depletion pressure, the compositions of both the produced well stream and the retrograde liquid are measured. These data are included as a control composition in the event that the study is used for compositional material-balance purposes.

  The composition data can be used with equilibrium constants (determined by either laboratory measurements or general correlations) to determine recovery at the various stages of pressure depletion represented by the laboratory measurements. In this case, initial condensate content was 181.74 STB/Mrcf (213 STB/Mscf), and the amount recovered from the dewpoint to 700 psig was 51.91 STB/Mrcf. The gas formation volume factor was determined to be 0.6472 RB/Mscf at initial conditions and 0.6798 RB/Mscf at the dewpoint. If a hydrocarbon pore space of 500 × 10 6 ft 3 were determined from volumetric calculations, then from these data and those presented in Table 3, recoveries by pressure depletion would be

  These calculations indicate the large amount of liquid remaining in the reservoir at depletion even with excellent drainage to the wells. Further reductions in recovery would be expected because of areas of the reservoir inadequately drained with existing wells.

  To deal with such phase-behavior effects in more than an empirical manner requires the use of PVT simulators. These simulators are based on EOSs that describe the phase volumes and compositions of liquid and gaseous phases as functions of pressure and temperature. Because hydrocarbon molecules interact with each other in solution, the coefficients in an EOS are not always adequately known. PVT tests such as those described, along with the known composition of the original fluid, can be used to "tune" an appropriate EOS to achieve results that nearly match the measurements. Once this tuning process is complete, those coefficients can then be used to make predictions under differing operating conditions with some degree of reliability.

  Equations of state

  When the effects of complex phase behavior on phase compositions and physical properties cannot be calculated accurately with simple approaches, it is often desirable to use an equation of state (EOS). An EOS approach is often necessary when dealing with volatile oils and retrograde-condensate gases.

  EOSs provide a numerical method for calculating both composition and relative amount for each phase present in the system. In reservoir simulation, EOS calculations are typically restricted to two hydrocarbon phases: a liquid (oleic) phase and a gaseous phase. However, there are situations in which an aqueous phase is included in the EOS calculations, or even in which a third hydrocarbon-containing phase may be present (e.g., in CO₂ flooding). These are generally done in more advanced compositional simulators.

  The two most common EOSs used in petroleum engineering applications are the Peng-Robinson and Soave-Redlich-Kwong equations, which historically were derived from van der Waals’ equation. These three equations are called "cubic" because they result in a cubic representation for the molar volume. The basic equations are as follows: