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Oil fluid characteristics

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.

Contents

 1 Volatile and black oil fluid characteristics

 2 Oil fluid properties

 3 References

 4 Noteworthy papers in OnePetro

 5 External links

 6 See also

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.


Table 1

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 volatilizedoil 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 inFig. 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.



Fig. 1 – (a) Initial formation volume factor (FVF) and (b) initial dissolved GOR as a function of initial fluid 

molecular weight.
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:

 Oil formation volume factor (FVF) (Bo)

 Gas FVF (Bg)

 Dissolved GOR (Rs)

 Volatilized oil/gas ratio (Rv)

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 materialbalance 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.


Fig. 2 – Standard PVT properties as a function of pressure for a west Texas black oil.



Fig. 3 – Oil and gas viscosities as a function of pressure for west Texas black oil.



Table 2



Table 3

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.



Table 4



Fig. 4 – Standard PVT properties as a function of pressure for a Louisiana volatile oil.



Table 5
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:

 Walsh-Towler algorithm [13]

 Whitson-Torp method [7]

 Equation-of-state (EOS) method [14][15]

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.

References

1. ↑ McCain Jr., W.D. 1994. Heavy Components Control Reservoir Fluid Behavior. J Pet Technol 46 (9): 

746-750. SPE-28214-PA.http://dx.doi.org/10.2118/28214-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. http://dx.doi.org/10.2118/1209-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. http://dx.doi.org/10.2118/10067-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.http://dx.doi.org/10.2118/15835-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. http://dx.doi.org/10.2118/11197-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. http://dx.doi.org/10.2118/4272-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. http://dx.doi.org/10.2118/7903-PA.

17. ↑ Alani, G.H. and Kennedy, H.T. 1960. Volumes of Liquid Hydrocarbons at High Temperatures and 

Pressures. Trans., AIME 219, 288.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Crude oil characterization

Material balance in oil reservoirs

PEH:Oil_Reservoir_Primary_Drive_Mechanisms

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