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Oil fluid characteristics

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Oil reservoirs are classified according to their fluid type. There are three broad oil classes. In order of increasing molecular weight, they are volatile oil, black oil, and heavy oil. Heavy-oil reservoirs are of minor interest during pressure depletion because they typically yield only marginal amounts of oil because of their low dissolved-gas contents and high fluid viscosities. The distinguishing characteristic between volatile and black oils is the stock-tank-oil content of their equilibrium gases. Equilibrium gases liberated from volatile oils contain appreciable stock-tank or condensable liquids whereas the gases from black oils contain negligible stock-tank liquids. While this distinction leads to only slightly different recovery strategies, it leads to very different methods of analysis and mathematical modeling requirements.

Volatile and black oil fluid characteristics

The petroleum fluid spectrum is gradational. There is no strict definition of volatile and black oils; there are only general guidelines and characteristics. Despite this lack of precision and the occasional confusion it brings, classification is quite useful and popular.

Molecular weight is a useful yardstick. Black oils typically range from 70 to 150 in molecular weight but may range as high as 190 to 210. In contrast, volatile oils are lower in molecular weight than black oils and typically range from 43 to 70. Oils with molecular weights greater than 210 usually are classified as heavy oils. Fluids with molecular weights of less than 43 are generally gases, which include gas condensates, wet gases, and dry gases. A molecular weight of 43 marks the lower molecular-weight limit of volatile oils.

Black and volatile oils are sometimes subdivided into different fluid types. For instance, volatile oils include near-critical fluids and high-shrinkage oils. Near-critical fluids represent light volatile oils and can include some very rich condensates. High-shrinkage oils represent the high-molecular-weight end of volatile oils and can include some light black oils.

Volatile and black oils are characterized in terms of a number of different properties. Table 1 summarizes their characteristics. This table includes the properties of the full range of petroleum fluids, including gases.

The defining property that distinguishes black and volatile oils is the volatilized-oil content of their equilibrium gases. The volatilized-oil content of a gas represents its condensable liquid portion. Condensable refers to the portion that condenses or "drops out" during pressure reduction and ultimately results as stock-tank liquid. Condensation may take place within the reservoir as the gas passes through the lease separators. Physically, intermediate-hydrocarbon components, typically C2 through C7, dominate this fraction. Volatilized oil also is called lease condensate or distillate. Gas condensates and wet gases also contain volatilized oil. Volatilized oil is reported conventionally as part of the crude-oil reserves and production. It should not be confused with and is distinctly different from natural-gas liquids. Natural-gas liquids are derived from the gas-processing plant and are called plant products.

The volatilized-oil content of gases is quantified in terms of their volatilized-oil/gas ratio, typically expressed in units of STB/MMscf or stock-tank m3 per std m3 of separator gas. The volatilized-oil/gas ratio of equilibrium gases of black oils is usually less than 1 to 10 STB/MMscf (approximately 0.04 to 0.4 gal/Mscf).The volatilized-oil content of these gases is so low that it usually is ignored. In contrast, the volatilized-oil content of gases from volatile oils is much greater. Their volatilized-oil/gas ratio typically ranges from 10 to 300 STB/MMscf or 0.4 to 8 gal/Mscf.

Several benchmark properties can be correlated with the reservoir fluid’s initial molecular weight. Fig. 1 plots the initial formation volume factor (FVF) and initial dissolved gas/oil ratio (GOR) as a function of reservoir-fluid molecular weight for 36 reservoir fluids. The abscissa in Fig. 1 spans from a molecular weight of 15 to 180. This range of molecular weights covers the full spectrum of petroleum fluids ranging from dry gases to heavy oils.

Volatile oils exhibit an initial oil FVF in the range of 1.5 to 3.0. Black oils exhibit an initial oil FVF in the range of 1.1 to 1.5. Volatile oils exhibit an initial GOR in the range of 900 to 3,500 scf/STB. Black oils exhibit an initial GOR in the range of 200 to 900 scf/STB. These relations establish molecular weight as a credible correlating parameter. McCain[1] has found success in the use of the heptanes-plus content as a correlating parameter.

The inverse of the oil FVF yields a measure of the original oil in place (OOIP) per unit volume of reservoir pore space. Because the oil FVF is greater for volatile oils than black oils, the latter yield greater OOIP per unit volume. Black-oil reservoirs contain 850 to 1130 STB/acre-ft (bulk) while volatile-oil reservoirs contain less, typically 400 to 850 STB/acre-ft.

Although volatile-oil reservoirs contain less oil per unit volume, they typically yield slightly higher oil recoveries than black-oil reservoirs because of their higher dissolved-gas content and lower oil viscosity. Ultimately, volatile-oil reservoirs may yield greater oil reserves than black-oil reservoirs. Light black oils and heavy volatile oils are among the most economically attractive reservoir fluids.

There has been no systematic study to determine the relative percentage of black-oil and volatile-oil reservoirs; however, an examination of the world’s 500 largest reservoirs reveals that black-oil reservoirs overwhelmingly dominate the group. [2] One reason there are more black-oil than volatile-oil reservoirs is that the latter are characteristically located at greater depths than the former. As exploration continues to go deeper, more volatile-oil reservoirs can be expected to be discovered.

Oil fluid properties

Black and volatile oils, as well as other petroleum fluids, are characterized routinely in terms of their standard pressure/volume/temperature (PVT) parameters:

These fluid properties, in addition to some others, are prerequisites for a wide variety of reservoir-engineering calculations, including estimating the original oil in place (OOIP) and original gas in place (OGIP) and material-balance calculations.

Table 2 tabulates and Fig. 2 plots the standard PVT parameters as a function of pressure for a black oil from a west Texas reservoir located at a depth of 6,700 ft with an initial pressure of 3,100 psia and a temperature of 131°F. Only the PVT properties below 2,000 psia are listed. The fluid exhibited a bubblepoint at approximately 1,688 psia and had a molecular weight of 81. Table 3 summarizes its compositional analysis. The fluid has an initial oil FVF of 1.467 RB/STB and dissolved GOR of 838 scf/STB. The equilibrium gas contains negligible volatilized oil. Fig. 3 plots the oil and gas viscosities as a function of pressure.

Table 4 tabulates and Fig. 4 plots the standard PVT parameters for a volatile oil from a north-central Louisiana reservoir located at a depth of approximately 10,000 ft with an initial pressure of 5,070 psia and a temperature of 246°F. [3][4] The fluid exhibited a bubblepoint at approximately 4,677 psia and had a molecular weight of 47. Table 5 summarizes the initial fluid composition. The fluid has an initial oil FVF of 2.704 RB/STB and dissolved GOR of 2,909 scf/STB. The bubblepoint gas had a volatilized-oil/gas ratio of approximately 120 STB/MMscf. The volatilized-oil/gas ratio decreases with pressure until a pressure of 998 psia is reached. At pressures between 998 and 598 psia, the volatilized-oil/gas ratio increases slightly.

The standard PVT parameters of volatile and black oils are determined experimentally with different laboratory procedures. Black oils are evaluated with a differential-vaporization (DV) experiment; [5][6] in contrast, volatile oils are evaluated with constant volume depletion (CVD). [7][8] Sometimes, however, volatile oils use a specialized DV experiment[9] instead of a CVD experiment. The specialized DV experiment includes a step to measure the volatilized-oil content of equilibrium gases.

The standard PVT parameters for black oils are specified routinely in commercial PVT reports. McCain provides some example PVT reports. [10] The reported PVT parameters, however, may or may not be adjusted for the effects of surface separators. Surface separators maximize the stock-tank liquid yield as fluids pass through them. The oil FVF and dissolved GOR of adjusted properties are characteristically less than unadjusted properties. If the PVT report specifies the adjusted parameters, then no further adjustment is required. If only the raw parameters are specified, then adjustment is needed. > Various empirical methods are used to correct the standard PVT parameters for the effects of separators. [11][12][5] Generally, correction is very important. For example, the unadjusted bubblepoint oil FVF and the dissolved GOR for the example black oil in Table 1 are 1.584 RB/stock tank barrels (STB) and 1,007 scf/STB, respectively. On adjustment for separators at 100 psia, the corresponding oil FVF and dissolved GOR are 1.467 RB/STB and 838.5 scf/STB, reflecting increased stock-tank-liquid recovery. Failure to correct the standard PVT parameters for separators can lead to substantial errors in subsequent reservoir-engineering calculations including the volumetric OOIP and OGIP calculations. Volatile oils are even more sensitive to the effects of separators than black oils. Volatile oils, however, are subjected to an entirely different laboratory procedure for measurement.

The standard PVT parameters for volatile oils rarely are given in commercial PVT reports. They must be calculated from CVD measurements. In order of increasing complexity, the three methods to calculate standard PVT parameters are:

The Walsh-Towler algorithm uses recovery data directly from the CVD measurement and computes the corresponding properties. This method is suited for spreadsheet calculation and is fast and simple. The Whitson-Torp method, in contrast, uses equilibrium gas-composition data and computes the properties with Standing’s[16] low-pressure K- values and a stock-tank-liquid density correlation such as the Alani-Kennedy EOS. [17] This method requires iterative, K -value flash calculations. Although this method is more computationally intensive than the Walsh-Towler algorithm, it is more versatile because it allows for arbitrary separator conditions. The EOS method is much more computationally intensive than the other methods. This method tunes a cubic EOS to the attending phase behavior and then uses the EOS to simulate the CVD numerically and estimate the PVT parameters. This method regularly uses commercial software. The methods yield virtually identical results despite their differences.


  1. McCain Jr., W.D. 1994. Heavy Components Control Reservoir Fluid Behavior. J Pet Technol 46 (9): 746-750. SPE-28214-PA. +
  2. Carmalt, S.W. and St. John, B. 1984. Giant Oil and Gas Fields. In Future of Petroleum Provinces of the World, ed. M.T. Halbouty. American Assn. of Petroleum Geologists.
  3. Cordell, J.C. and Ebert, C.K. 1965. A Case History Comparison of Predicted and Actual Performance of a Reservoir Producing Volatile Crude Oil. J Pet Technol 17 (11): 1291-1293. SPE-1209-PA.
  4. Jacoby, R.H. and Berry, V.J. Jr. 1957. A Method for Predicting Depletion Performance of a Reservoir Producing Volatile Crude Oil. Trans., AIME 210: 27.
  5. 5.0 5.1 Amyx, J.W., Bass, D.M., and Whiting, R.L. 1960. Petroleum Reservoir Engineering—Physical Properties. New York City: McGraw-Hill Book Co. Inc.
  6. Dodson, C.R., Goodwill, D, and Mayer, E.H. 1953. Application of Laboratory PVT Data to Reservoir Engineering Problems. Trans., AIME 198: 287.
  7. 7.0 7.1 Whitson, C.H. and Torp, S.B. 1983. Evaluating Constant-Volume Depletion Data. J Pet Technol 35 (3): 610-620. SPE-10067-PA.
  8. Ahmed, T. 1989. Hydrocarbon Phase Behavior. Houston, Texas: Gulf Publishing Co.
  9. Reudelhuber, F.O. and Hinds, R.F. 1957. A Compositional Material Balance Method for Prediction of Recovery from Volatile Oil Depletion Drive Reservoirs. Trans., AIME 210, 19.
  10. McCain, W.D. 1990. The Properties of Petroleum Fluids. Tulsa, Oklahoma: PennWell Publishing Co.
  11. Moses, P.L. 1986. Engineering Applications of Phase Behavior of Crude Oil and Condensate Systems (includes associated papers 16046, 16177, 16390, 16440, 19214 and 19893 ). J Pet Technol 38 (7): 715-723. SPE-15835-PA.
  12. Poettmann, F.H. and Thompson, R.S.: "Discussion of Engineering Applications of Phase Behavior of Crude Oil and Condensate Systems," JPT (November 1986) 1263.
  13. Walsh, M.P. and Towler, B.F. 1995. Method Computes PVT Properties for Gas Condensates. Oil & Gas J. (31 July): 83.
  14. Coats, K.H. and Smart, G.T. 1986. Application of a Regression-Based EOS PVT Program to Laboratory Data. SPE Res Eng 1 (3): 277-299. SPE-11197-PA.
  15. Cook, R.E., Jacoby, R.H., and Ramesh, A.B. 1974. A Beta-Type Reservoir Simulator for Approximating Compositional Effects During Gas Injection. Society of Petroleum Engineers Journal 14 (5): 471-481. SPE-4272-PA.
  16. Standing, M.B. 1979. A Set of Equations for Computing Equilibrium Ratios of a Crude Oil/Natural Gas System at Pressures Below 1,000 psia. J Pet Technol 31 (9): 1193-1195. SPE-7903-PA.
  17. Alani, G.H. and Kennedy, H.T. 1960. Volumes of Liquid Hydrocarbons at High Temperatures and Pressures. Trans., AIME 219, 288.

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See also

Crude oil characterization

Material balance in oil reservoirs