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Difference between revisions of "Interfacial tension"

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Interfacial or surface tension exists when two phases are present. These phases can be gas/oil, oil/water, or gas/water. Interfacial tension is the force that holds the surface of a particular phase together and is normally measured in dynes/cm. The surface tension between gas and crude oil ranges from near zero to approximately 34 dynes/cm. It is a function of pressure, temperature, and the composition of each phase.
+
Interfacial or surface tension exists when two phases are present. These phases can be gas/oil, oil/water, or gas/water. Interfacial tension is the force that holds the surface of a particular phase together and is normally measured in dynes/cm. The surface tension between gas and crude oil ranges from near zero to approximately 34 dynes/cm. It is a function of pressure, temperature, and the composition of each phase.
  
==Approaches to determine gas/oil surface tension==
+
== Approaches to determine gas/oil surface tension ==
Two forms of correlations for calculating gas/oil surface tension have been developed.
 
  
*The first form is a pseudocompositional black oil approach. Two components, gas and oil, are identified, and techniques used with compositional models are used to calculate surface tension.  
+
Two forms of correlations for calculating gas/oil surface tension have been developed.
  
*The second approach uses empirical correlations to determine surface tension.  
+
*The first form is a pseudocompositional black oil approach. Two components, gas and oil, are identified, and techniques used with compositional models are used to calculate surface tension.
  
Black oil correlations may provide less than accurate results because of the simplified characterization of the crude oil. Generally, the heavy end components of a crude oil may be made of asphaltic and surface active materials that have a measurable effect on surface tension.  
+
*The second approach uses empirical correlations to determine surface tension.
  
With the compositional approach, surface tension is determined from the following equation proposed by Weinaug and Katz. <ref name="r1"/>
+
Black oil correlations may provide less than accurate results because of the simplified characterization of the crude oil. Generally, the heavy end components of a crude oil may be made of asphaltic and surface active materials that have a measurable effect on surface tension.
  
[[File:Vol1 page 0282 eq 001.png]]....................(1)
+
With the compositional approach, surface tension is determined from the following equation proposed by Weinaug and Katz. <ref name="r1">Weinaug, C.F. and Katz, D.L. 1943. Surface Tensions of Methane-Propane Mixtures. Ind. Eng. Chem. 35 (2): 239-246. http://dx.doi.org/10.1021/ie50398a028</ref>
  
where the density terms are defined with units of g/cm<sup>3</sup>. ''P''<sub>''i''</sub> is the parachor of each component. This property is a characteristic of pure components and is determined from surface tension measurements where the density of the gas and liquid phases are known. '''Fig. 1''' provides a relationship between parachors and molecular weight.  
+
[[File:Vol1 page 0282 eq 001.png|RTENOTITLE]]....................(1)
 +
 
 +
where the density terms are defined with units of g/cm<sup>3</sup>. ''P''<sub>''i''</sub> is the parachor of each component. This property is a characteristic of pure components and is determined from surface tension measurements where the density of the gas and liquid phases are known. '''Fig. 1<ref name="r2">Katz, D.L., Monroe, R.R., and Trainer, R.P. 1943. Surface tension of crude oils containing dissolved gases. AIME Technical Publication 1624, American Institute of Mining and Metallurgical Engineers, New York, 285–294.</ref>''' provides a relationship between parachors and molecular weight.
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
Line 20: Line 21:
 
</gallery>
 
</gallery>
  
==Models to calculate surface tension==
+
== Models to calculate surface tension ==
In 1973, Ramey<ref name="r3"/> proposed a pseudocompositional method for calculating surface tension. The two components are oil and gas. Gas is free to dissolve in the oil phase, and oil is free to vaporize in the gas phase, which makes this method more versatile than the other methods discussed in this chapter. The Weinaug-Katz equation is modified as
+
 
 +
In 1973, Ramey<ref name="r3">Ramey, H.J. Jr. 1973. Correlations of Surface and Interfacial Tensions of Reservoir Fluids. Paper SPE-4429-MS available from SPE, Richardson, Texas.</ref> proposed a pseudocompositional method for calculating surface tension. The two components are oil and gas. Gas is free to dissolve in the oil phase, and oil is free to vaporize in the gas phase, which makes this method more versatile than the other methods discussed in this chapter. The Weinaug-Katz equation is modified as
  
[[File:Vol1 page 0283 eq 001.png]]....................(2)
+
[[File:Vol1 page 0283 eq 001.png|RTENOTITLE]]....................(2)
  
 
where the oil mole fraction in the oil phase is defined as
 
where the oil mole fraction in the oil phase is defined as
  
[[File:Vol1 page 0283 eq 002.png]]....................(3)
+
[[File:Vol1 page 0283 eq 002.png|RTENOTITLE]]....................(3)
  
 
and the gas mole fraction in oil is
 
and the gas mole fraction in oil is
  
[[File:Vol1 page 0283 eq 003.png]]....................(4)
+
[[File:Vol1 page 0283 eq 003.png|RTENOTITLE]]....................(4)
  
 
The mole fraction of oil and gas in the as phase is
 
The mole fraction of oil and gas in the as phase is
  
[[File:Vol1 page 0283 eq 004.png]]....................(5)
+
[[File:Vol1 page 0283 eq 004.png|RTENOTITLE]]....................(5)
  
 
and
 
and
  
[[File:Vol1 page 0283 eq 005.png]]....................(6)
+
[[File:Vol1 page 0283 eq 005.png|RTENOTITLE]]....................(6)
  
The traditional assumption used with the black oil approach is that the oil vaporized in the gas phase, ''r''<sub>''v''</sub>, is zero. In this instance, ''y''<sub>''o''</sub> = 0 and ''y''<sub>''g''</sub> = 1, which simplifies '''Eqs. 5''' and '''6'''.  
+
The traditional assumption used with the black oil approach is that the oil vaporized in the gas phase, ''r''<sub>''v''</sub>, is zero. In this instance, ''y''<sub>''o''</sub> = 0 and ''y''<sub>''g''</sub> = 1, which simplifies '''Eqs. 5''' and '''6'''.
  
 
The average molecular weights of the oil and gas phases are defined as
 
The average molecular weights of the oil and gas phases are defined as
  
[[File:Vol1 page 0284 eq 001.png]]....................(7)
+
[[File:Vol1 page 0284 eq 001.png|RTENOTITLE]]....................(7)
  
 
and
 
and
  
[[File:Vol1 page 0284 eq 002.png]]....................(8)
+
[[File:Vol1 page 0284 eq 002.png|RTENOTITLE]]....................(8)
  
 
Liquid and gas densities are defined with units of g/cm<sup>3</sup>:
 
Liquid and gas densities are defined with units of g/cm<sup>3</sup>:
  
[[File:Vol1 page 0284 eq 003.png]]....................(9)
+
[[File:Vol1 page 0284 eq 003.png|RTENOTITLE]]....................(9)
  
 
and
 
and
  
[[File:Vol1 page 0284 eq 004.png]]....................(10)
+
[[File:Vol1 page 0284 eq 004.png|RTENOTITLE]]....................(10)
  
Whitson and Brulé<ref name="r4"/> suggested the following parachor equations, which reproduce the graphical methods suggested by Ramey:
+
Whitson and Brulé<ref name="r4">Whitson, C.H. and Brulé, M.R. 2000. Phase Behavior, No. 20, Chap. 3. Richardson, Texas: Henry L. Doherty Monograph Series, Society of Petroleum Engineers.</ref> suggested the following parachor equations, which reproduce the graphical methods suggested by Ramey:
  
[[File:Vol1 page 0284 eq 005.png]]....................(11)
+
[[File:Vol1 page 0284 eq 005.png|RTENOTITLE]]....................(11)
  
 
and
 
and
  
[[File:Vol1 page 0285 eq 001.png]]....................(12)
+
[[File:Vol1 page 0285 eq 001.png|RTENOTITLE]]....................(12)
 
 
 
 
In 1989, Asheim<ref name="r5"/> presented another pseudocompositional correlation for surface tension. With the assumption that no oil vaporizes into the gas phase, the resulting equation is
 
  
[[File:Vol1 page 0285 eq 002.png]]....................(13)
+
In 1989, Asheim<ref name="r5">Asheim, H. 1989. Extension of the Black-Oil Model To Predict Interfacial Tension. Paper SPE-19383-MS available from SPE, Richardson, Texas.</ref> presented another pseudocompositional correlation for surface tension. With the assumption that no oil vaporizes into the gas phase, the resulting equation is
  
where the [[Gas formation volume factor and density|gas formation volume factor]] (FVF), ''B''<sub>''g''</sub>, is defined as
+
[[File:Vol1 page 0285 eq 002.png|RTENOTITLE]]....................(13)
  
[[File:Vol1 page 0285 eq 003.png]]....................(14)
+
where the [[Gas_formation_volume_factor_and_density|gas formation volume factor]] (FVF), ''B''<sub>''g''</sub>, is defined as
  
 +
[[File:Vol1 page 0285 eq 003.png|RTENOTITLE]]....................(14)
  
 
Asheim proposed the following equations to calculate the parachors for the oil and gas phases.
 
Asheim proposed the following equations to calculate the parachors for the oil and gas phases.
  
[[File:Vol1 page 0285 eq 004.png]]....................(15)
+
[[File:Vol1 page 0285 eq 004.png|RTENOTITLE]]....................(15)
  
[[File:Vol1 page 0285 eq 005.png]]....................(16)
+
[[File:Vol1 page 0285 eq 005.png|RTENOTITLE]]....................(16)
  
While this method appears different from that proposed by Ramey, it is identical for the Ramey case in which no oil vaporizes into the gas phase. This method differs from Ramey’s method only by the definition of the oil and gas parachors.  
+
While this method appears different from that proposed by Ramey, it is identical for the Ramey case in which no oil vaporizes into the gas phase. This method differs from Ramey’s method only by the definition of the oil and gas parachors.
  
The Baker and Swerdloff <ref name="r6"/><ref name="r7"/> method was published in 1955. It was presented in the form of graphs for estimating gas/oil surface tension ('''Fig. 2''').  
+
The Baker and Swerdloff <ref name="r6">Baker, O. and Swerdloff, W. 1955. Calculation of Surface Tension 3—Calculating parachor Values. Oil Gas J. (5 December 1955): 141.</ref><ref name="r7">Baker, O. and Swerdloff, W. 1956. Calculation of Surface Tension 6—Finding Surface Tension of Hydrocarbon Liquids. Oil Gas J. (2 January 1956): 125.</ref> method was published in 1955. It was presented in the form of graphs for estimating gas/oil surface tension ('''Fig. 2''').
  
<gallery widths=300px heights=200px>
+
<gallery widths="300px" heights="200px">
 
File:vol1 Page 298 Image 0001.png|'''Fig. 2 – Surface tension of crude oil at atmospheric pressure (after Baker and Swerdloff<ref name="r7" />).'''
 
File:vol1 Page 298 Image 0001.png|'''Fig. 2 – Surface tension of crude oil at atmospheric pressure (after Baker and Swerdloff<ref name="r7" />).'''
 
</gallery>
 
</gallery>
  
Equations to calculate the dead oil surface tension at 68 and 100°F are  
+
Equations to calculate the dead oil surface tension at 68 and 100°F are
  
[[File:Vol1 page 0286 eq 001.png]]....................(17)
+
[[File:Vol1 page 0286 eq 001.png|RTENOTITLE]]....................(17)
  
 
and
 
and
  
[[File:Vol1 page 0286 eq 002.png]]....................(18)
+
[[File:Vol1 page 0286 eq 002.png|RTENOTITLE]]....................(18)
 
 
  
Beggs<ref name="r8"/> suggests that for temperatures greater than 100°F, the value calculated for 100°F should be used. Similarly, if the temperature is less than 68°F, the value calculated for 68°F should be used. For intermediate temperatures, surface tension is derived by linear interpolation as described by
+
Beggs<ref name="r8">Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.</ref> suggests that for temperatures greater than 100°F, the value calculated for 100°F should be used. Similarly, if the temperature is less than 68°F, the value calculated for 68°F should be used. For intermediate temperatures, surface tension is derived by linear interpolation as described by
  
[[File:Vol1 page 0286 eq 003.png]]....................(19)
+
[[File:Vol1 page 0286 eq 003.png|RTENOTITLE]]....................(19)
  
 
At pressures greater than atmospheric pressure, gas is dissolved in the oil, which reduces surface tension. Baker and Swerdloff provided the graphical correction factor shown in '''Fig. 3''', which can be reproduced mathematically by
 
At pressures greater than atmospheric pressure, gas is dissolved in the oil, which reduces surface tension. Baker and Swerdloff provided the graphical correction factor shown in '''Fig. 3''', which can be reproduced mathematically by
  
[[File:Vol1 page 0287 eq 001.png]]....................(20)
+
[[File:Vol1 page 0287 eq 001.png|RTENOTITLE]]....................(20)
  
 
The live oil surface tension is then derived from
 
The live oil surface tension is then derived from
  
[[File:Vol1 page 0288 eq 001.png]]....................(21)
+
[[File:Vol1 page 0288 eq 001.png|RTENOTITLE]]....................(21)
  
<gallery widths=300px heights=200px>
+
<gallery widths="300px" heights="200px">
 
File:vol1 Page 299 Image 0001.png|'''Fig. 3 – Effect of solution gas on crude oil surface tension (after Baker and Swerdloff<ref name="r7" />).'''
 
File:vol1 Page 299 Image 0001.png|'''Fig. 3 – Effect of solution gas on crude oil surface tension (after Baker and Swerdloff<ref name="r7" />).'''
 
</gallery>
 
</gallery>
  
In 2000, Abdul-Majeed<ref name="r9"/> presented an update to Baker and Swerdloff’s correlation. Surface tension data from 18 crude oils covering the temperature range 60 to 130°F was used to derive '''Eq. 22''', which '''Fig. 4''' shows graphically.
+
In 2000, Abdul-Majeed<ref name="r9">Abdul-Majeed, G.H. and Abu Al-Soof, N.B. 2000. Estimation of gas–oil surface tension. J. Pet. Sci. Eng. 27 (3–4): 197-200. http://dx.doi.org/10.1016/S0920-4105(00)00058-9</ref> presented an update to Baker and Swerdloff’s correlation. Surface tension data from 18 crude oils covering the temperature range 60 to 130°F was used to derive '''Eq. 22''', which '''Fig. 4''' shows graphically.
  
[[File:Vol1 page 0288 eq 002.png]]....................(22)
+
[[File:Vol1 page 0288 eq 002.png|RTENOTITLE]]....................(22)
  
Data acquired from 42 crude oil/gas systems was used to develop the live oil correction factor. These data, shown graphically in '''Fig. 5''', can be represented by  
+
Data acquired from 42 crude oil/gas systems was used to develop the live oil correction factor. These data, shown graphically in '''Fig. 5''', can be represented by
  
[[File:Vol1 page 0288 eq 003.png]]....................(23)
+
[[File:Vol1 page 0288 eq 003.png|RTENOTITLE]]....................(23)
  
As with the Baker and Swerdloff method, the live oil surface tension is given by '''Eq. 21'''. '''Table 1''' shows the statistics provided by Abdul-Majeed comparing the results of the proposed method with the Baker and Swerdloff method. '''Fig. 6''' shows a comparison of the four methods for calculating interfacial tension.  
+
As with the Baker and Swerdloff method, the live oil surface tension is given by '''Eq. 21'''. '''Table 1''' shows the statistics provided by Abdul-Majeed comparing the results of the proposed method with the Baker and Swerdloff method. '''Fig. 6''' shows a comparison of the four methods for calculating interfacial tension.
  
<gallery widths=300px heights=200px>
+
<gallery widths="300px" heights="200px">
 
File:Vol1 Page 301 Image 0001.png|'''Table 1'''
 
File:Vol1 Page 301 Image 0001.png|'''Table 1'''
  
Line 136: Line 135:
 
</gallery>
 
</gallery>
  
==Water-hydrocarbon surface tension==
+
== Water-hydrocarbon surface tension ==
The surface tension of a water-hydrocarbon system varies from approximately 72 dynes/cm for water/gas systems to 20 to 40 dynes/cm for water/oil systems at atmospheric conditions. In 1973, Ramey<ref name="r3"/> published methods to evaluate the surface tension of water-hydrocarbon mixtures. Unfortunately, this work was for liquid hydrocarbons and did not extend into the gas-phase region. A later publication by Firoozabadi and Ramey<ref name="r10"/> provided a more generalized correlation suitable for use with gas and liquid hydrocarbons. Surface tension data from pure components ranging from n-dodecane to methane were plotted as shown in '''Fig. 7'''. The surface tension function used for the ''y''-axis is
 
  
[[File:Vol1 page 0289 eq 001.png]]....................(24)
+
The surface tension of a water-hydrocarbon system varies from approximately 72 dynes/cm for water/gas systems to 20 to 40 dynes/cm for water/oil systems at atmospheric conditions. In 1973, Ramey<ref name="r3">Ramey, H.J. Jr. 1973. Correlations of Surface and Interfacial Tensions of Reservoir Fluids. Paper SPE-4429-MS available from SPE, Richardson, Texas.</ref> published methods to evaluate the surface tension of water-hydrocarbon mixtures. Unfortunately, this work was for liquid hydrocarbons and did not extend into the gas-phase region. A later publication by Firoozabadi and Ramey<ref name="r10">Firoozabadi, A. and Ramey Jr., H.J. 1988. Surface Tension of Water-Hydrocarbon Systems at Reservoir Conditions. J Can Pet Technol 27 (May–June): 41–48.</ref> provided a more generalized correlation suitable for use with gas and liquid hydrocarbons. Surface tension data from pure components ranging from n-dodecane to methane were plotted as shown in '''Fig. 7'''. The surface tension function used for the ''y''-axis is
 +
 
 +
[[File:Vol1 page 0289 eq 001.png|RTENOTITLE]]....................(24)
  
 
while the density difference between the water and hydrocarbon phase is plotted on the ''x''-axis. The data in '''Fig. 7''' can be represented by
 
while the density difference between the water and hydrocarbon phase is plotted on the ''x''-axis. The data in '''Fig. 7''' can be represented by
  
[[File:Vol1 page 0289 eq 002.png]]....................(25)
+
[[File:Vol1 page 0289 eq 002.png|RTENOTITLE]]....................(25)
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
Line 151: Line 151:
 
Solving for surface tension, the relationship becomes
 
Solving for surface tension, the relationship becomes
  
[[File:Vol1 page 0289 eq 003.png]]....................(26)
+
[[File:Vol1 page 0289 eq 003.png|RTENOTITLE]]....................(26)
  
This equation requires that the pseudocritical temperature of the oil and gas phases be calculated to evaluate reduced temperature. Riazi’s<ref name="r11"/> relationship for liquid hydrocarbons can be modified to yield
+
This equation requires that the pseudocritical temperature of the oil and gas phases be calculated to evaluate reduced temperature. Riazi’s<ref name="r11">Riazi, M.R. and Daubert, T.E. 1980. Simplify Property Predictions. Hydrocarb. Process. 59 (3): 115–116.</ref> relationship for liquid hydrocarbons can be modified to yield
  
[[File:Vol1 page 0290 eq 001.png]]....................(27)
+
[[File:Vol1 page 0290 eq 001.png|RTENOTITLE]]....................(27)
  
Sutton’s<ref name="r12"/> equation for pseudocritical temperature can be used for the gas phase:
+
Sutton’s<ref name="r12">Sutton, R.P.: "Compressibility Factors for High-Molecular-Weight Reservoir Gases," paper SPE 14265 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22–25 September.</ref> equation for pseudocritical temperature can be used for the gas phase:
  
[[File:Vol1 page 0290 eq 002.png]]....................(28)
+
[[File:Vol1 page 0290 eq 002.png|RTENOTITLE]]....................(28)
  
 
When the pressure increases and gas dissolves into the oil phase, the composition of that phase changes. The pseudocritical temperature of the mixture can be evaluated by calculating the mole fraction of each component present in the oil. For the oil component, we have
 
When the pressure increases and gas dissolves into the oil phase, the composition of that phase changes. The pseudocritical temperature of the mixture can be evaluated by calculating the mole fraction of each component present in the oil. For the oil component, we have
  
[[File:Vol1 page 0290 eq 003.png]]....................(29)
+
[[File:Vol1 page 0290 eq 003.png|RTENOTITLE]]....................(29)
  
 
while the gas mole fraction in oil is
 
while the gas mole fraction in oil is
  
[[File:Vol1 page 0290 eq 004.png]]....................(30)
+
[[File:Vol1 page 0290 eq 004.png|RTENOTITLE]]....................(30)
  
 
The pseudocritical temperature of the mixture is then the mole fraction weighted average pseudocritical temperature of each component:
 
The pseudocritical temperature of the mixture is then the mole fraction weighted average pseudocritical temperature of each component:
  
[[File:Vol1 page 0290 eq 005.png]]....................(31)
+
[[File:Vol1 page 0290 eq 005.png|RTENOTITLE]]....................(31)
  
This work serves as a guide for estimating the surface tension between water and hydrocarbons. Firoozabadi and Ramey recommended that a single point measurement for oil water systems be obtained so that the curve in '''Fig. 7''' could be appropriately adjusted. '''Fig. 8''' shows an example of results for oil/water and gas/water systems derived from this method.  
+
This work serves as a guide for estimating the surface tension between water and hydrocarbons. Firoozabadi and Ramey recommended that a single point measurement for oil water systems be obtained so that the curve in '''Fig. 7''' could be appropriately adjusted. '''Fig. 8''' shows an example of results for oil/water and gas/water systems derived from this method.
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
Line 179: Line 179:
 
</gallery>
 
</gallery>
  
For methane-brine systems, Standing<ref name="r4"/> has indicated that the surface tension will increase according to '''Fig. 9'''. The relationship in '''Fig. 9''' can be approximated by  
+
For methane-brine systems, Standing<ref name="r4">Whitson, C.H. and Brulé, M.R. 2000. Phase Behavior, No. 20, Chap. 3. Richardson, Texas: Henry L. Doherty Monograph Series, Society of Petroleum Engineers.</ref> has indicated that the surface tension will increase according to '''Fig. 9'''. The relationship in '''Fig. 9''' can be approximated by
  
[[File:Vol1 page 0291 eq 001.png]]....................(32)
+
[[File:Vol1 page 0291 eq 001.png|RTENOTITLE]]....................(32)
  
 
<gallery widths="300px" heights="200px">
 
<gallery widths="300px" heights="200px">
Line 187: Line 187:
 
</gallery>
 
</gallery>
  
==Nomenclature==
+
== Nomenclature ==
 +
 
 
{|
 
{|
|''B''<sub>''g''</sub>
 
|=
 
|gas FVF, ft<sup>3</sup>/scf
 
 
|-
 
|-
|''B''<sub>''o''</sub>  
+
| ''B''<sub>''g''</sub>
|=  
+
| =
|oil FVF, bbl/STB  
+
| gas FVF, ft<sup>3</sup>/scf
 +
|-
 +
| ''B''<sub>''o''</sub>
 +
| =
 +
| oil FVF, bbl/STB
 
|-
 
|-
|''K''<sub>''w''</sub>  
+
| ''K''<sub>''w''</sub>
|=  
+
| =
|Watson characterization factor, °R<sup>1/3</sup>  
+
| Watson characterization factor, °R<sup>1/3</sup>
 
|-
 
|-
|''M''<sub>''g''</sub>  
+
| ''M''<sub>''g''</sub>
|=  
+
| =
|gas molecular weight, m, lbm/lbm mol  
+
| gas molecular weight, m, lbm/lbm mol
 
|-
 
|-
|''M''<sub>''go''</sub>  
+
| ''M''<sub>''go''</sub>
|=  
+
| =
|gas/oil mixture molecular weight, m, lbm/lbm mol  
+
| gas/oil mixture molecular weight, m, lbm/lbm mol
 
|-
 
|-
|''M''<sub>''o''</sub>  
+
| ''M''<sub>''o''</sub>
|=  
+
| =
|oil molecular weight, m, lbm/lbm mol  
+
| oil molecular weight, m, lbm/lbm mol
 
|-
 
|-
|''M''<sub>''og''</sub>  
+
| ''M''<sub>''og''</sub>
|=  
+
| =
|oil-gas mixture molecular weight, m, lbm/lbm mol  
+
| oil-gas mixture molecular weight, m, lbm/lbm mol
 
|-
 
|-
|''p''  
+
| ''p''
|=  
+
| =
|pressure, m/Lt<sup>2</sup>, psia  
+
| pressure, m/Lt<sup>2</sup>, psia
 
|-
 
|-
|''p''<sub>''b''</sub>  
+
| ''p''<sub>''b''</sub>
|=  
+
| =
|bubblepoint pressure, m/Lt<sup>2</sup>, psia  
+
| bubblepoint pressure, m/Lt<sup>2</sup>, psia
 
|-
 
|-
|''T''  
+
| ''T''
|=  
+
| =
|temperature, T, °F  
+
| temperature, T, °F
 
|-
 
|-
|''T''<sub>''cg''</sub>  
+
| ''T''<sub>''cg''</sub>
|=  
+
| =
|gas pseudocritical temperature, T, °R  
+
| gas pseudocritical temperature, T, °R
 
|-
 
|-
|''T''<sub>''cm''</sub>  
+
| ''T''<sub>''cm''</sub>
|=  
+
| =
|mixture pseudocritical temperature, T, °R  
+
| mixture pseudocritical temperature, T, °R
 
|-
 
|-
|''T''<sub>''co''</sub>  
+
| ''T''<sub>''co''</sub>
|=  
+
| =
|oil pseudocritical temperature, T, °R  
+
| oil pseudocritical temperature, T, °R
 
|-
 
|-
|''T''<sub>''r''</sub>  
+
| ''T''<sub>''r''</sub>
|=  
+
| =
|reduced temperature, T  
+
| reduced temperature, T
 
|-
 
|-
|''T''<sub>''sc''</sub>  
+
| ''T''<sub>''sc''</sub>
|=  
+
| =
|temperature at standard conditions, T, °F  
+
| temperature at standard conditions, T, °F
 
|-
 
|-
|''x''<sub>''g''</sub>  
+
| ''x''<sub>''g''</sub>
|=  
+
| =
|gas "component" mole fraction in oil  
+
| gas "component" mole fraction in oil
 
|-
 
|-
|''x''<sub>''o''</sub>  
+
| ''x''<sub>''o''</sub>
|=  
+
| =
|oil "component" mole fraction in oil  
+
| oil "component" mole fraction in oil
 
|-
 
|-
|''y''<sub>''g''</sub>  
+
| ''y''<sub>''g''</sub>
|=  
+
| =
|gas "component" mole fraction in gas  
+
| gas "component" mole fraction in gas
 
|-
 
|-
|''yo''  
+
| ''yo''
|=  
+
| =
|oil "component" mole fraction in gas  
+
| oil "component" mole fraction in gas
 
|-
 
|-
|''γ''<sub>''g''</sub>  
+
| ''γ''<sub>''g''</sub>
|=  
+
| =
|gas specific gravity, air=1  
+
| gas specific gravity, air=1
 
|-
 
|-
|''γ''<sub>''ghc''</sub>  
+
| ''γ''<sub>''ghc''</sub>
|=  
+
| =
|gas specific gravity of hydrocarbon components in a gas mixture, air=1  
+
| gas specific gravity of hydrocarbon components in a gas mixture, air=1
 
|-
 
|-
|''γ''<sub>''gs''</sub>  
+
| ''γ''<sub>''gs''</sub>
|=  
+
| =
|separator gas specific gravity, air=1  
+
| separator gas specific gravity, air=1
 
|-
 
|-
|''γ''<sub>''o''</sub>  
+
| ''γ''<sub>''o''</sub>
|=  
+
| =
|oil specific gravity  
+
| oil specific gravity
 
|-
 
|-
|''Z''  
+
| ''Z''
|=  
+
| =
|gas compressibility factor  
+
| gas compressibility factor
 
|-
 
|-
|''ρ''<sub>''g''</sub>  
+
| ''ρ''<sub>''g''</sub>
|=  
+
| =
|gas density, m/L<sup>3</sup>, lbm/ft<sup>3</sup>  
+
| gas density, m/L<sup>3</sup>, lbm/ft<sup>3</sup>
 
|-
 
|-
|''ρ''<sub>''o''</sub>  
+
| ''ρ''<sub>''o''</sub>
|=  
+
| =
|oil density, m/L<sup>3</sup>, lbm/ft<sup>3</sup>  
+
| oil density, m/L<sup>3</sup>, lbm/ft<sup>3</sup>
 
|-
 
|-
|''σ''<sub>''go''</sub>  
+
| ''σ''<sub>''go''</sub>
|=  
+
| =
|gas/oil surface tension, m/t<sup>2</sup>, dynes/cm  
+
| gas/oil surface tension, m/t<sup>2</sup>, dynes/cm
 
|-
 
|-
|''σ''<sub>''od''</sub>  
+
| ''σ''<sub>''od''</sub>
|=  
+
| =
|dead oil surface tension, m/t<sup>2</sup>, dynes/cm
+
| dead oil surface tension, m/t<sup>2</sup>, dynes/cm
 
|-
 
|-
|''P''  
+
| ''P''
|=  
+
| =
|parachor
+
| parachor
 
|-
 
|-
|''P''<sub>''g''</sub>  
+
| ''P''<sub>''g''</sub>
|=  
+
| =
|gas parachor  
+
| gas parachor
 
|-
 
|-
|''P''<sub>''i''</sub>  
+
| ''P''<sub>''i''</sub>
|=  
+
| =
|parachor of each component  
+
| parachor of each component
 
|-
 
|-
|''P''<sub>''o''</sub>  
+
| ''P''<sub>''o''</sub>
|=  
+
| =
|oil parachor  
+
| oil parachor
 
|-
 
|-
|''R''<sub>''s''</sub>  
+
| ''R''<sub>''s''</sub>
|=  
+
| =
|solution GOR, scf/STB  
+
| solution GOR, scf/STB
 
|-
 
|-
|''p''<sub>''sc''</sub>  
+
| ''p''<sub>''sc''</sub>
|=  
+
| =
|pressure at standard conditions, m/Lt<sup>2</sup>, psia  
+
| pressure at standard conditions, m/Lt<sup>2</sup>, psia
 
|-
 
|-
|''ρ''<sub>''h''</sub>  
+
| ''ρ''<sub>''h''</sub>
|=  
+
| =
|hydrocarbon density, m/L<sup>3</sup>, g/cm<sup>3</sup>
+
| hydrocarbon density, m/L<sup>3</sup>, g/cm<sup>3</sup>
 
|-
 
|-
|[[File:Vol1 page 0306 inline 001.png]]
+
| [[File:Vol1 page 0306 inline 001.png|RTENOTITLE]]
|=  
+
| =
|dead oil surface tension at 68°F, m/t<sup>2</sup>, dynes/cm  
+
| dead oil surface tension at 68°F, m/t<sup>2</sup>, dynes/cm
 
|-
 
|-
|''σ''<sub>''hw''</sub>  
+
| ''σ''<sub>''hw''</sub>
|=  
+
| =
|hydrocarbon/water surface tension, m/t<sup>2</sup>, dynes/cm  
+
| hydrocarbon/water surface tension, m/t<sup>2</sup>, dynes/cm
 
|-
 
|-
|''ρ''<sub>''w''</sub>  
+
| ''ρ''<sub>''w''</sub>
|=  
+
| =
|water density, m/L<sup>3</sup>, g/cm<sup>3</sup>  
+
| water density, m/L<sup>3</sup>, g/cm<sup>3</sup>
 
|-
 
|-
|''ρ''<sub>''h''</sub>  
+
| ''ρ''<sub>''h''</sub>
|=  
+
| =
|hydrocarbon density, m/L<sup>3</sup>, g/cm<sup>3</sup>
+
| hydrocarbon density, m/L<sup>3</sup>, g/cm<sup>3</sup>
 
|-
 
|-
|''C''<sub>''sw''</sub>  
+
| ''C''<sub>''sw''</sub>
|=  
+
| =
|salt concentration in water, ppm  
+
| salt concentration in water, ppm
 
|-
 
|-
|''r''<sub>''v''</sub>  
+
| ''r''<sub>''v''</sub>
|=  
+
| =
|vaporized oil/gas ratio, STB/scf  
+
| vaporized oil/gas ratio, STB/scf
 
|-
 
|-
|''x''<sub>''i''</sub>  
+
| ''x''<sub>''i''</sub>
|=  
+
| =
|component ''i'' mole fraction in oil phase  
+
| component ''i'' mole fraction in oil phase
 
|-
 
|-
|''y''<sub>''i''</sub>  
+
| ''y''<sub>''i''</sub>
|=  
+
| =
|component i mole fraction in gas phase  
+
| component i mole fraction in gas phase
 
|}
 
|}
  
==References==
+
== References ==
<references>
+
 
<ref name="r1">Weinaug, C.F. and Katz, D.L. 1943. Surface Tensions of Methane-Propane Mixtures. ''Ind. Eng. Chem''. '''35''' (2): 239-246. http://dx.doi.org/10.1021/ie50398a028</ref>
+
<references />
<ref name="r2">Katz, D.L., Monroe, R.R., and  Trainer, R.P. 1943. Surface tension of crude oils containing dissolved gases. AIME Technical Publication 1624, American Institute of Mining and Metallurgical Engineers, New York, 285–294.</ref>
+
 
<ref name="r3">Ramey, H.J. Jr. 1973. Correlations of Surface and Interfacial Tensions of Reservoir Fluids. Paper SPE-4429-MS available from SPE, Richardson, Texas.</ref>
+
== Noteworthy papers in OnePetro ==
<ref name="r4">Whitson, C.H. and Brulé, M.R. 2000. ''Phase Behavior'', No. 20, Chap. 3. Richardson, Texas: Henry L. Doherty Monograph Series, Society of Petroleum Engineers.</ref>
 
<ref name="r5">Asheim, H. 1989. Extension of the Black-Oil Model To Predict Interfacial Tension. Paper SPE-19383-MS available from SPE, Richardson, Texas.</ref>
 
<ref name="r6">Baker, O. and Swerdloff, W. 1955. Calculation of Surface Tension 3—Calculating parachor Values. ''Oil Gas J''. (5 December 1955): 141.</ref>
 
<ref name="r7">Baker, O. and Swerdloff, W. 1956. Calculation of Surface Tension 6—Finding Surface Tension of Hydrocarbon Liquids. ''Oil Gas J''. (2 January 1956): 125.</ref>
 
<ref name="r8">Bradley, H.B. 1987. ''Petroleum Engineering Handbook''. Richardson, Texas: SPE.</ref>
 
<ref name="r9">Abdul-Majeed, G.H. and Abu Al-Soof, N.B. 2000. Estimation of gas–oil surface tension. ''J. Pet. Sci. Eng''. '''27''' (3–4): 197-200. http://dx.doi.org/10.1016/S0920-4105(00)00058-9</ref>
 
<ref name="r10">Firoozabadi, A. and Ramey Jr., H.J. 1988. Surface Tension of Water-Hydrocarbon Systems at Reservoir Conditions. ''J Can Pet Technol'' '''27''' (May–June): 41–48.</ref>
 
<ref name="r11">Riazi, M.R. and Daubert, T.E. 1980. Simplify Property Predictions. ''Hydrocarb. Process.'' 59 (3): 115–116.</ref>
 
<ref name="r12">Sutton, R.P.: "Compressibility Factors for High-Molecular-Weight Reservoir Gases," paper SPE 14265 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22–25 September. </ref>
 
</references>
 
  
==Noteworthy papers in OnePetro==
 
 
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
 
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
  
==External links==
+
== External links ==
 +
 
 
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
 
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
  
==See also==
+
== See also ==
[[Oil fluid properties]]
+
 
 +
[[Oil_fluid_properties|Oil fluid properties]]
  
[[PEH:Oil System Correlations]]
+
[[PEH:Oil_System_Correlations]]
 +
[[Category:5.2.1 Phase behavior and PVT measurements]]

Latest revision as of 16:05, 4 June 2015

Interfacial or surface tension exists when two phases are present. These phases can be gas/oil, oil/water, or gas/water. Interfacial tension is the force that holds the surface of a particular phase together and is normally measured in dynes/cm. The surface tension between gas and crude oil ranges from near zero to approximately 34 dynes/cm. It is a function of pressure, temperature, and the composition of each phase.

Approaches to determine gas/oil surface tension

Two forms of correlations for calculating gas/oil surface tension have been developed.

  • The first form is a pseudocompositional black oil approach. Two components, gas and oil, are identified, and techniques used with compositional models are used to calculate surface tension.
  • The second approach uses empirical correlations to determine surface tension.

Black oil correlations may provide less than accurate results because of the simplified characterization of the crude oil. Generally, the heavy end components of a crude oil may be made of asphaltic and surface active materials that have a measurable effect on surface tension.

With the compositional approach, surface tension is determined from the following equation proposed by Weinaug and Katz. [1]

RTENOTITLE....................(1)

where the density terms are defined with units of g/cm3. Pi is the parachor of each component. This property is a characteristic of pure components and is determined from surface tension measurements where the density of the gas and liquid phases are known. Fig. 1[2] provides a relationship between parachors and molecular weight.

Models to calculate surface tension

In 1973, Ramey[3] proposed a pseudocompositional method for calculating surface tension. The two components are oil and gas. Gas is free to dissolve in the oil phase, and oil is free to vaporize in the gas phase, which makes this method more versatile than the other methods discussed in this chapter. The Weinaug-Katz equation is modified as

RTENOTITLE....................(2)

where the oil mole fraction in the oil phase is defined as

RTENOTITLE....................(3)

and the gas mole fraction in oil is

RTENOTITLE....................(4)

The mole fraction of oil and gas in the as phase is

RTENOTITLE....................(5)

and

RTENOTITLE....................(6)

The traditional assumption used with the black oil approach is that the oil vaporized in the gas phase, rv, is zero. In this instance, yo = 0 and yg = 1, which simplifies Eqs. 5 and 6.

The average molecular weights of the oil and gas phases are defined as

RTENOTITLE....................(7)

and

RTENOTITLE....................(8)

Liquid and gas densities are defined with units of g/cm3:

RTENOTITLE....................(9)

and

RTENOTITLE....................(10)

Whitson and Brulé[4] suggested the following parachor equations, which reproduce the graphical methods suggested by Ramey:

RTENOTITLE....................(11)

and

RTENOTITLE....................(12)

In 1989, Asheim[5] presented another pseudocompositional correlation for surface tension. With the assumption that no oil vaporizes into the gas phase, the resulting equation is

RTENOTITLE....................(13)

where the gas formation volume factor (FVF), Bg, is defined as

RTENOTITLE....................(14)

Asheim proposed the following equations to calculate the parachors for the oil and gas phases.

RTENOTITLE....................(15)

RTENOTITLE....................(16)

While this method appears different from that proposed by Ramey, it is identical for the Ramey case in which no oil vaporizes into the gas phase. This method differs from Ramey’s method only by the definition of the oil and gas parachors.

The Baker and Swerdloff [6][7] method was published in 1955. It was presented in the form of graphs for estimating gas/oil surface tension (Fig. 2).

Equations to calculate the dead oil surface tension at 68 and 100°F are

RTENOTITLE....................(17)

and

RTENOTITLE....................(18)

Beggs[8] suggests that for temperatures greater than 100°F, the value calculated for 100°F should be used. Similarly, if the temperature is less than 68°F, the value calculated for 68°F should be used. For intermediate temperatures, surface tension is derived by linear interpolation as described by

RTENOTITLE....................(19)

At pressures greater than atmospheric pressure, gas is dissolved in the oil, which reduces surface tension. Baker and Swerdloff provided the graphical correction factor shown in Fig. 3, which can be reproduced mathematically by

RTENOTITLE....................(20)

The live oil surface tension is then derived from

RTENOTITLE....................(21)

In 2000, Abdul-Majeed[9] presented an update to Baker and Swerdloff’s correlation. Surface tension data from 18 crude oils covering the temperature range 60 to 130°F was used to derive Eq. 22, which Fig. 4 shows graphically.

RTENOTITLE....................(22)

Data acquired from 42 crude oil/gas systems was used to develop the live oil correction factor. These data, shown graphically in Fig. 5, can be represented by

RTENOTITLE....................(23)

As with the Baker and Swerdloff method, the live oil surface tension is given by Eq. 21. Table 1 shows the statistics provided by Abdul-Majeed comparing the results of the proposed method with the Baker and Swerdloff method. Fig. 6 shows a comparison of the four methods for calculating interfacial tension.

Water-hydrocarbon surface tension

The surface tension of a water-hydrocarbon system varies from approximately 72 dynes/cm for water/gas systems to 20 to 40 dynes/cm for water/oil systems at atmospheric conditions. In 1973, Ramey[3] published methods to evaluate the surface tension of water-hydrocarbon mixtures. Unfortunately, this work was for liquid hydrocarbons and did not extend into the gas-phase region. A later publication by Firoozabadi and Ramey[10] provided a more generalized correlation suitable for use with gas and liquid hydrocarbons. Surface tension data from pure components ranging from n-dodecane to methane were plotted as shown in Fig. 7. The surface tension function used for the y-axis is

RTENOTITLE....................(24)

while the density difference between the water and hydrocarbon phase is plotted on the x-axis. The data in Fig. 7 can be represented by

RTENOTITLE....................(25)

Solving for surface tension, the relationship becomes

RTENOTITLE....................(26)

This equation requires that the pseudocritical temperature of the oil and gas phases be calculated to evaluate reduced temperature. Riazi’s[11] relationship for liquid hydrocarbons can be modified to yield

RTENOTITLE....................(27)

Sutton’s[12] equation for pseudocritical temperature can be used for the gas phase:

RTENOTITLE....................(28)

When the pressure increases and gas dissolves into the oil phase, the composition of that phase changes. The pseudocritical temperature of the mixture can be evaluated by calculating the mole fraction of each component present in the oil. For the oil component, we have

RTENOTITLE....................(29)

while the gas mole fraction in oil is

RTENOTITLE....................(30)

The pseudocritical temperature of the mixture is then the mole fraction weighted average pseudocritical temperature of each component:

RTENOTITLE....................(31)

This work serves as a guide for estimating the surface tension between water and hydrocarbons. Firoozabadi and Ramey recommended that a single point measurement for oil water systems be obtained so that the curve in Fig. 7 could be appropriately adjusted. Fig. 8 shows an example of results for oil/water and gas/water systems derived from this method.

For methane-brine systems, Standing[4] has indicated that the surface tension will increase according to Fig. 9. The relationship in Fig. 9 can be approximated by

RTENOTITLE....................(32)

Nomenclature

Bg = gas FVF, ft3/scf
Bo = oil FVF, bbl/STB
Kw = Watson characterization factor, °R1/3
Mg = gas molecular weight, m, lbm/lbm mol
Mgo = gas/oil mixture molecular weight, m, lbm/lbm mol
Mo = oil molecular weight, m, lbm/lbm mol
Mog = oil-gas mixture molecular weight, m, lbm/lbm mol
p = pressure, m/Lt2, psia
pb = bubblepoint pressure, m/Lt2, psia
T = temperature, T, °F
Tcg = gas pseudocritical temperature, T, °R
Tcm = mixture pseudocritical temperature, T, °R
Tco = oil pseudocritical temperature, T, °R
Tr = reduced temperature, T
Tsc = temperature at standard conditions, T, °F
xg = gas "component" mole fraction in oil
xo = oil "component" mole fraction in oil
yg = gas "component" mole fraction in gas
yo = oil "component" mole fraction in gas
γg = gas specific gravity, air=1
γghc = gas specific gravity of hydrocarbon components in a gas mixture, air=1
γgs = separator gas specific gravity, air=1
γo = oil specific gravity
Z = gas compressibility factor
ρg = gas density, m/L3, lbm/ft3
ρo = oil density, m/L3, lbm/ft3
σgo = gas/oil surface tension, m/t2, dynes/cm
σod = dead oil surface tension, m/t2, dynes/cm
P = parachor
Pg = gas parachor
Pi = parachor of each component
Po = oil parachor
Rs = solution GOR, scf/STB
psc = pressure at standard conditions, m/Lt2, psia
ρh = hydrocarbon density, m/L3, g/cm3
RTENOTITLE = dead oil surface tension at 68°F, m/t2, dynes/cm
σhw = hydrocarbon/water surface tension, m/t2, dynes/cm
ρw = water density, m/L3, g/cm3
ρh = hydrocarbon density, m/L3, g/cm3
Csw = salt concentration in water, ppm
rv = vaporized oil/gas ratio, STB/scf
xi = component i mole fraction in oil phase
yi = component i mole fraction in gas phase

References

  1. Weinaug, C.F. and Katz, D.L. 1943. Surface Tensions of Methane-Propane Mixtures. Ind. Eng. Chem. 35 (2): 239-246. http://dx.doi.org/10.1021/ie50398a028
  2. 2.0 2.1 Katz, D.L., Monroe, R.R., and Trainer, R.P. 1943. Surface tension of crude oils containing dissolved gases. AIME Technical Publication 1624, American Institute of Mining and Metallurgical Engineers, New York, 285–294.
  3. 3.0 3.1 Ramey, H.J. Jr. 1973. Correlations of Surface and Interfacial Tensions of Reservoir Fluids. Paper SPE-4429-MS available from SPE, Richardson, Texas.
  4. 4.0 4.1 4.2 Whitson, C.H. and Brulé, M.R. 2000. Phase Behavior, No. 20, Chap. 3. Richardson, Texas: Henry L. Doherty Monograph Series, Society of Petroleum Engineers.
  5. Asheim, H. 1989. Extension of the Black-Oil Model To Predict Interfacial Tension. Paper SPE-19383-MS available from SPE, Richardson, Texas.
  6. Baker, O. and Swerdloff, W. 1955. Calculation of Surface Tension 3—Calculating parachor Values. Oil Gas J. (5 December 1955): 141.
  7. 7.0 7.1 7.2 Baker, O. and Swerdloff, W. 1956. Calculation of Surface Tension 6—Finding Surface Tension of Hydrocarbon Liquids. Oil Gas J. (2 January 1956): 125.
  8. Bradley, H.B. 1987. Petroleum Engineering Handbook. Richardson, Texas: SPE.
  9. Abdul-Majeed, G.H. and Abu Al-Soof, N.B. 2000. Estimation of gas–oil surface tension. J. Pet. Sci. Eng. 27 (3–4): 197-200. http://dx.doi.org/10.1016/S0920-4105(00)00058-9
  10. Firoozabadi, A. and Ramey Jr., H.J. 1988. Surface Tension of Water-Hydrocarbon Systems at Reservoir Conditions. J Can Pet Technol 27 (May–June): 41–48.
  11. Riazi, M.R. and Daubert, T.E. 1980. Simplify Property Predictions. Hydrocarb. Process. 59 (3): 115–116.
  12. Sutton, R.P.: "Compressibility Factors for High-Molecular-Weight Reservoir Gases," paper SPE 14265 presented at the 1985 SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22–25 September.

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

Oil fluid properties

PEH:Oil_System_Correlations