- Email: [email protected]
Vapour-liquid equilibrium study of methane and western shale oil
Vapour-liquid and western Paul
equilibrium shale oil
study of methane
F. Meier
Phillips Petroleum Company, Bartlesville, OK 74004, USA (Received 23 October 1984; revised 4 October 1985)
The bubble point pressures, saturated molar liquid volumes, and densities of a shale oil from the Green River formation in Utah, and a distillation fraction of the oil were experimentally determined as a function of temperature and methane mole fraction. These properties were measured in a static VLE apparatus capable of measuring pressures to 34,500 kPa and temperatures to 450 K. The phase change at the bubble point for the mixtures of oil and methane was determined using the statistical method of splines. The densities for the crude shale oil have been extrapolated to 288.7K (60°F) using a standard API correlation.
(Keywords: shale oil; methane; vapour-liquid
equilibrium)
of multicomponent vapourliquid The prediction equilibrium (VLE) for non-ideal mixtures is a difficult but important problem in the petroleum industry. Accurate P-V-T-X data for pure components and petroleum mixtures are needed to develop accurate and predictive liquid density correlations. Liquid densities are widely used in chemical process calculations, simulations, and liquid metering calculations. Existing correlations are not always appropriate for synthetic fuels such as coal, shale, and tar sands liquids since these oils have more aromatic and heteroatom-containing compounds, as well as lower hydrogen to carbon ratios, than typical crude oils. Consequently, VLE data are needed for synthetic fuels or for mode1 compounds which are representative of synthetic fuel components. There are many examples of VLE data in the literature for binary mixtures in which the heavier component could be considered a representative or mode1 component of a synthetic fuel. For example, the dependence of the bubble point pressure on methane mole fraction was studied at a few temperatures for benzene’s* and toluene*. Chao’s group at Purdue University has measured binary VLE data of hydrogen with tetralin, bicyclohexyl, quinoline, toluene, and thianaphthene3-’ at four temperatures and seven pressures. Similarly, Nasir and Kobayashi’ measured binary VLE data of hydrogen with 9methylanthracene, dibenzofuran, and 22ethylanthraquinone at numerous temperatures and pressures. Some VLE data for synthetic fuels are also available from the literature. The development of the coal liquefaction process has resulted in the measurement of VLE data for hydrogen, methane and hydrogen sulphide mixtures with coal liquids and distillate fractions of the have been liquids ‘*lo Also gas solubility measurements made for an Athabasca bitumen saturated with carbon dioxide, methane, or nitrogen”. Vapour--liquid equilibrium data for mixtures of shale oil or a shale oil fraction and methane are measured in this study. The shale oil was obtained from the Green River formation in Utah by retorting the shale using the Union B process. This study reports densities, bubble point 0016-2361/86/050663-06$3.00 (’ 1986 Butterworth & Co. (Publishers)
Ltd.
pressures, and saturated liquid volumes as a function of methane mole fraction and temperature. This type of data may be used to test existing correlations for saturated liquid densities. For example, the critical properties of the shale oil may be predicted using the generalized equation of Riazi and Daubert’* ; then a saturated liquid density correlation such as the Yen-Woodsi3, modified Rackett14, Gunn and Yamada15, or Costald equation” may be used to examine the use and accuracy of these correlations in predicting the experimental data. EXPERIMENTAL The experimental apparatus used to make the PVT measurements is shown in Figure 1. The apparatus contains many of the same features as the apparatus described by Nasir et al. 17-18. However, the principal approach is the same as that described by Sage et a/.19. The main part of the equilibrium cell is a hand-driven 1OOccRuska variable volume positive displacement pump Mode1 2200. The pump has a maximum pressure rating of 55,158 kPa, is made of A-286 stainless steel, and has a vernier scale marked in divisions of 0.01~~. The pump piston is packed with teflon chevron rings containing 20% glass; the glass increases the temperature rating of the rings to approximately 450K. These rings limit the maximum working temperature of the whole system. The main feature of this design is that the Ruska pump has been inverted to eliminate dead space volume. The inverted pump piston is driven by two steel gears. Internal system pressure is measured indirectly using a Ruska Differential Null Pressure Indicator (DPI) Model 2437, a high temperature transducer model. The maximum working pressure for the DPI is 68,948 kPa and the maximum sensitivity is 0.014 kPa. The VLE system pressure is measured by balancing the DPI to null using argon gas, and measuring the argon pressure on a 34,474 kPa Heise gauge. The Heise gauge was calibrated with a Ruska dead weight gauge model 500&701 with an accuracy of 0.04%. The Heise gauge is the limiting pressure device for the system. High pressure argon is
FUEL, 1986, Vol 65, May
663
Vapour-liquid
equilibrium
study of Green River shale oil: P. F. Meier is directly related to the volume change according to Equation (1). Next, PVT measurements were made in the following manner. The variable volume Ruska pump was screwed in manually until the system pressure was approximately 34,474 kPa; difficulty in turning the Ruska pump plus a rapid pressure rise indicated that the system was liquid full. Pressure-volume measurements were made by varying system volume in 0.5~~ increments until the pressure change with volume decreased significantly; then volume changes were increased to several cc units. In this manner, pressure-volume data were obtained over the single and two phase region. At the end of each isothermal experiment, the variable volume Ruska pump was screwed into the same system volume as the first measurement and compared with the first measured pressure. These measurements were reproduced to k 5 psi and exhibited the excellent long-term leakage behaviour of the VLE system.
Figure
1 Experimental
apparatus
used to make PVT measurements
generated with an Aminco compressor which has a maximum pressure capability of 68,948 kPa. A system over-pressure condition is controlled by an AutoclaveEngineers rupture disc. The achievement of equilibrium is aided by an EMCO (Electra-Mechanics Co.) circulating pump Model 101. The pump has a maximum working pressure of 68,948 kPa and is sealed with Kalrez O-rings. Control of the equilibrium system temperature environment is accomplished using a silicone oil bath. The oil is GE silicone oil SF 9650 with a maximum temperature limit of 533K. The clean system volume was calculated as a function of temperature using methane gas. The volume was calculated using the second-order virial equation shown in Equation (1).
RESULTS Compositional data and some properties of the shale oil and shale oil fraction are given in Table 1. The shale oil fraction is a 4.4 wt% cut of the shale oil and was obtained using a 36 mm diameter fractionation column. The bubble point pressure is often determined by taking many P-V measurements over a narrow change in volume and then obtaining the bubble point by graphical interpolation. In this study we have calculated the bubble point pressure by fitting the experimental P-V data to two polynomial equations, one for the vapour-liquid and one for the liquid-full regions, and finding the join point of the two equations using the method of splines. Splines are generally defined as a piecewise polynomials of degree n whose function values and n- 1 derivatives agree at the point they join 21. Data points w ere assigned to the single
Table 1 fraction
The second-order virial constant, b, was calculated according to the equation given by Pitzer and Cur12’ which is shown below.
Properties
and compositional
Cc. distillation wt% distilled
(2)
For methane, a critical temperature of 190.6K, a critical pressure of 4604 kPa, and an acentric factor of 0.007 were used to calculate fl at different testing temperatures. Before any testing was done on the shale oil, it was evacuated to remove dissolved air. Hydrocarbons removed from the oil as a result of this procedure were collected in a liquid nitrogen cooled trap. The removed hydrocarbons were less than 0.5 wt% of the original charge. PVT measurements were made on the sample at this point to obtain the oil density as a function of temperature. Methane was then charged to the equilibrium system using a 250~ Ruska pump to measure the volume of the methane charged. The temperature and pressure of the 25Occ Ruska charging pump were the same at the beginning and end of the addition of methane gas to the equilibrium system; thus, the molar addition of methane
664
FUEL, 1986, Vol 65, May
Oil
Fraction
260 464 573 652 720 782 845 912 992 1101” 1362”
282 346 369 385 398 411 424 434 447 463 663
_
&(0.1445+0.073~)-(0.330~0.460(7;’ ’ -(0.1385+0.500)1;-2-(0.0121+0.097~)7;~3 -o.o073oT,-s
data of the shale oil and shale oil
no Gasoline - IBP - 400’F “i Diesel - 40&650’F :6 Vacuum gas oil - 65&100O”F U’,1000°F + residue Pour point (“C) Molecular weight (gmoleei) Refractive index EIrmenral Carbon Hydrogen Nitrogen Oxygen Sulphur ’
5.4 24.9 51.7 18.0 +15 282 1.5218
UnalJses (WY%)
Obtained
83.20 10.17 2.41 2.98 0.64 by extrapolation
41.7 58.0 0.3 - 53 185 1.4661
Vapour-liquid
3zo: Mole%Methane + Shale Oil - 313.2 K 1 I
I
I
0305
83
1
Volume - CkZ
0. te 5
DecitGZs
17.8 Mole%Methane + Shale Oil - 313.2 K
20000 4 i
l!
moo0
10000
5000
0
I
I
I
t53
0.275
1
0.293
0.315
I
0.333
0.
5
Volume - Cubic Decimeters Figure 2 Isotherms . sharp phase changes Table 2
Bubble point pressures,
Temperature 294.1 313.2 348.2 383.2 423.2
depicting
(K)
raw PV data
saturated
exhibiting
obscure
and
equilibrium
study
of Green River shale
or two phase region using a graphical plot of the data as a guide. For sharp breaks between the single and two-phase region, the assignment of data points was clear. At higher mole fractions of methane, the phase transition was not sharp, and the assignment of PV data points was not clear. In these cases, data were assigned on a trial basis and then reassigned as necessary to allow convergence of the spline method. The standard error of all the data points lit to the spline method never exceeded 275 kPa; in most cases, the error was considerably less. When the spline method clearly gave an anomalous bubble point pressure, a graphical interpolation was used to obtain the density, the saturated liquid volume, and the bubble point pressure. This occurred only at the higher methane mole fractions with the unfractionated shale oil. The type of polynomial equations used to fit the vapourliquid or liquid regions were selected primarily on the basis of the adequacy of the equation to tit the data rather than theoretical reasons. In theory, if the isothermal compressibility was a constant, a plot of In (volume) versus pressure would yield a straight line; however, the isothermal compressibility is a weak function of pressure, and it was found that a quadratic in the natural log of system volume gave a better fit for the liquid phase pressure. The same equation form was used to fit the two phase PV data. The density and molar volume of the shale oils in the absence of methane were determined using an equation for pressure which was linear in the natural log of system volume. Sample isotherms depicting the raw data are shown in Figure 2for data exhibiting sharp and obscure phase changes. The advantage of the spline method is that the bubble point pressure may be obtained with a relatively small data set compared with the graphical interpolation method. A control test with methane and n-decane was used to test the ability of the equipment and spline method to accurately determine the bubble point pressure for a vapour-liquid mixture. These pressures were compared with the results of Reamer et al.” which were obtained by graphical interpolation of PV data. The bubble point pressures we determined were only 335% larger than the pressures they reported. The long-term leakage behaviour
molar liquid volumes, and densities for the shale oil as a function
Bubble point pressure _._
_
(kPa)
_
oil: P. F. Meier
Saturated
of temperature
liquid volume (dma mole- r)
and methane
mole fraction
Density
(0.300)h 0.311 0.323 0.335 0.349
(0.9405,b 0.9060 0.8743 0.8429 0.8089
313.2 3482 383.2 423.2
Shale oil+ 17.8 mole :A CH, 5364 5978 6219 6578
0.267 0.275 0.287 0.299
0.8803 0.8525 0.8177 0.7846
313.2 348.2 383.2 423.2
Shale oil + 38.3 mole “0 CH, 15823” 16892” I8092 18078
0.207” 0.216 0.225 0.236
0.8717” 0.8341” 0.8005 0.7636
313.2 348.2 383.2 423.2
Shale oil + 54.4 mole :, CH, 28 165” 28992” 3 1268” 31164
0.168” 0.175” 0.18v 0.188”
0.8 166” 0.7854 0.7652” 0.733w
’ b
These numbers were determined by graphical interpolation This number is given for comparison only. Waxes are present
(kgdm
j)
in the oil at this temperature
FUEL, 1986, Vol 65, May
665
Vapour-liquid equilibrium study of Green River shale oil: P. F. Meier of our system was also established by measuring the bubble point pressure of a 50150 mole% mixture of methane and n-decane; during a four day interval, the bubble point pressure was repeatedly determined with less than 0.1% variation. Thus the control test demonstrated the ability of the equipment and spline method to reproduce literature data obtained by graphical interpolation. Also, there was no long-term leakage of the VLE equipment. Table 2 shows densities, saturated molar liquid volumes, and bubble point pressures measured for the western shale oil as a function of temperature and methane Table 3
Bubble point pressures,
saturated
mole fraction. Table 3 shows the same properties for the shale oil fraction. Some of these data have been graphically depicted. Figure 3 shows the shale oil density as a function of temperature. The apparently anomalous behaviour of the oil density below 313K (40°C) is explained by the presence of wax in the oil. Solvent dewaxing of the oil with methyl ethyl ketone at 273K indicated that the oil contains 7.9 wt% wax; this wax begins to crystallize from solution at 305K. Figure 4 shows that solid formation is not a problem at room temperature for the shale oil fraction. The bubble point pressure is shown as a function of
molar liquid volumes, and densities for the shale oil fraction
as a function
of temperature
and methane
mole
fraction Temperature
Bubble point pressure
(K)
294.7 313.2 348.2 383.2
Saturated
(kPa)
_ _ _ _
423.2 Shale oil fraction + 23.0 mole % CH, 6695 7302 7901 8205 Shale oil fraction f43.5 mole ?< CH, 16706 17409 18078 17864 Shale oil fraction f53.3 mole Y/, CH, 22504 23559 23725 23132
313.2 348.2 383.2 423.2 313.2 348.2 383.2 423.2 313.2 348.2 383.2 423.7
liquid volume
Density
(dm3 mole-‘)
0.218 0.223 0.233 0.243 0.255
0.8492 0.8294 0.7929 0.7613 0.7240
0.186 0.192 0.199 0.209
0.7870 0.7595 0.7328 0.6976
0.146 0.153 0.159 0.169
0.7636 0.7270 0.6997 0.6608
0.129 0.135 0.141 0.147
0.7368 0.7044 0.6749 0.6462
(kgdm
“)
0.08
0.95
I
0 0-M
Legend
Legend 0
0.90
$ s $ f c3
0.0 MOM &than0
A
17.S Mole% Methane
+
38.3 MOM Mothone
0.62
0
0.0 Mold
A
23.0 Mole% Ydhano
Methane
+
43.5 LloloX Methane
X
53.3 Mole% Mothano
OJJs
0.80
0.70 0.75
0.66
0.66
0.70
do
1
Figure 3
methane
666
Temperature mole fractions
FUEL,
1986,
0.64
340
Tempemture - K
dependence
4hO
300
4
of the shale oil density at different
Figure 4
different
VOI 65, May
400
350
Temper&n, Temperature dependence methane mole fractions
450
- K
of the shale oil fraction
density at
Vapour-liquid 30000
moo0
If
20000
Y
b i 3
l’ooo
2
3 3
lx4
10000
5oo:by, ,,,
cl Denana-344.3K q Shala011- 348.2 K E shp??_!?!_~~~?!_z~_r
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
equilibrium
study
of Green River shale
oil: P. F. Meier
pressures of the methane-decane system reported by Reamer et ~1.‘~ where a much larger data set was employed in the bubble point estimation. The variable volume pump used in collecting PV data was a convenient device for varying the VLE system volume without introducing any long-term leakage effects, as shown by the reproducibility of our experimental measurements at the highest measured pressure. The temperature dependence of the crude shale oil may be compared with that for a typical crude oil using the API volume correction factor formula described by Hankinson et ~1.~~. Using this formula and the crude oil constants for relating the thermal expansion coefficient at the base temperature to the base density, the densities of the crude shale oil in Table 2 (with no methane) may be extrapolated to 288.7K (60°F). This extrapolation leads to 60’F densities of 0.9224, 0.9147, 0.9079, and 0.9025 gee- ’ for the data reported at 313.2, 348.2, 383.2, and 423.2K, respectively. Thus the thermal expansion coefficient for an average crude oil is not appropriate for the shale oil used in this study. This calculation shows one difference between shale oil and crude oil and suggests that the compositional difference between shale oil and crude oil will result in similar discrepencies for other crude oil correlations.
Methane Mole Fraction Figure 5 Bubble point pressure dependence on methane mole fraction for benzene, toluene, decane, the shale oil. and the shale oil fraction
ACKNOWLEDGEMENT The author wishes to thank Nancy K. Phillips for doing the statistical spline method data-analysis. methane mole fraction in Figure 5 for the shale oil and shale oil fraction. For comparison, the same relationship is shown for benzene2, toluene2, and decane22,23 using the data of Elbishlawi and Spencer and Sage et ~1. The small difference in temperature for the three sets of data (10K) should not be enough to alter the following comparative statements. Within the range of mole fractions shown in the figure, decane shows the highest methane solubility at a given bubble point while benzene has the lowest solubility. Thus the shale oils are bracketed by these two pure compounds in terms of solubility. The solubility of toluene is similar to the solubility for the unfractionated shale oil and the shale oil fraction has a higher methane solubility than the unfractionated shale oil. The bubble point pressure is shown as a function of temperature in Figure 6 for the shale oil fraction at two methane concentrations. This figure indicates that the measured bubble points are in the region of isobaric and the cricondenbar is retrograde condensation, bracketed in this temperature range. This phenomena was also observed for the unfractionated shale oil (see Tab/e 2) at the experiments with the two higher methane mole fractions.
ZSOOPI-
!22OOPI-
21ooaI-
K I
Fizoooa ,-
f
16000 I-
16000 ,-
l_/m___
woo0
DISCUSSION The statisitical spline method was shown to be a useful tool for calculating the bubble point pressure, density, and saturated liquid volume of a vapour-liquid system. This method, using a limited data set from our experimental apparatus, accurately determined the bubble point
1.000
+
--------------
300
350
4
Tempemture Figure 6 Bubble point pressure shale oil fraction at two methane
IO
-;
dependence on temperature mole fractions
FUEL, 1986, Vol 65, May
for the
667
Vapour-liquid
equilibrium
study of Green River shale oil: P. F. Meier
REFERENCES 1 2 3 4 5 6 I 8 9 10
668
Schoch, E. P., Hoffman, A. E., Kasperik, A. S., Lightfoot, J. H. and Mayfield, F. D. Ind. Eng. Chem. 1940, 32(6), 788 Elbishlawi, M. and Spencer, .I. R. Ind. Eng. Chem. 1951, 43(8), 1811 Simnick, J. J., Lawson, C. C., Lin, H. M. and Chao, K. C. AIChE .I. 1977, 23, 469 Sebastian, H. M., Yao, J., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data 1978, 23, 167 Sebastian, H. M., Simnick, J. J., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data. 1978,23, 305 Simnick, J. J., Sebastian, H. M., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data 1978, 23, 339 Sebastian, H. M., Simnick, J. J., Lin, H. M. and Chao, K. C. Can. J. Chem. Eng. 1978, 56, 743 Nasir, P. and Kobayashi, R. J. Chem. Eng. Data 1981, 26, 321 Lin, H. M., Sebastian, H. M., Simnick, J. J. and Chao, K. C. Ind. Eng. Chem. Process Des. Dev. 1981, 20, 253 Wilson, G. M., Johnston, R. H., Hwang, S. C. and Tsonopoulos, C. Ind. Eng. Chem. Process Des. Deo. 1981, 20, 94
FUEL, 1986, Vol 65, May
11 12 13 14 15 16 17 18 19 20 21 22 23 24
Svrcek, W. Y. and Mehrotra, A. K. J. Can. Petroleum Tech. 1982, July-August, 31 Riazi, M. R. and Daubert, T. E. Hydrocarhotl Processing 1980, March, 115 Yen, L. C. and Woods, S. S. AIChE J. 1966, 12,95 Rackett, H. G. J. Chem. Eng. Data 1970, 15, 514 Gunn, R. D. and Yamada, T. AIChE J. 1971, 17, 1341 Hankinson, R. W. and Thomson, G. H. AIChE J. 1979,25,653 Nasir, P., Martin, R. J. and Kobayashi, R. Fluid Phase Equilibria 1981, 5, 279 Nasir, P., Ph.D. Dissertation, Rice University, 1980 Sage, B. H.. Schaafsma, J. G. and Lacey, W. N. Ind. Eng. Chem. 1934, 26, 1218 Pitzer, K. S. and Curl, R. F. Jr. J. Am. Chem. Sot. 1957, 79, 2369 Smith, P. L. The American Statistician 1979, 33, 57 Reamer, H. H., Olds, R. H., Sage, B. H. and Lacey, W. M. Ind. Eng. Chem. 1942, 34, 1526 Sage, B. H., Lavender, H. M. and Lacey, W. N. Ind. Eng. Chem. 1940, 32, 743 Hankinson, R. W., Segers, R. G., Buck, T. K. and Gielzecki, F. P. Oil and Gas J. 1979, December 24, 66
equilibrium shale oil
study of methane
F. Meier
Phillips Petroleum Company, Bartlesville, OK 74004, USA (Received 23 October 1984; revised 4 October 1985)
The bubble point pressures, saturated molar liquid volumes, and densities of a shale oil from the Green River formation in Utah, and a distillation fraction of the oil were experimentally determined as a function of temperature and methane mole fraction. These properties were measured in a static VLE apparatus capable of measuring pressures to 34,500 kPa and temperatures to 450 K. The phase change at the bubble point for the mixtures of oil and methane was determined using the statistical method of splines. The densities for the crude shale oil have been extrapolated to 288.7K (60°F) using a standard API correlation.
(Keywords: shale oil; methane; vapour-liquid
equilibrium)
of multicomponent vapourliquid The prediction equilibrium (VLE) for non-ideal mixtures is a difficult but important problem in the petroleum industry. Accurate P-V-T-X data for pure components and petroleum mixtures are needed to develop accurate and predictive liquid density correlations. Liquid densities are widely used in chemical process calculations, simulations, and liquid metering calculations. Existing correlations are not always appropriate for synthetic fuels such as coal, shale, and tar sands liquids since these oils have more aromatic and heteroatom-containing compounds, as well as lower hydrogen to carbon ratios, than typical crude oils. Consequently, VLE data are needed for synthetic fuels or for mode1 compounds which are representative of synthetic fuel components. There are many examples of VLE data in the literature for binary mixtures in which the heavier component could be considered a representative or mode1 component of a synthetic fuel. For example, the dependence of the bubble point pressure on methane mole fraction was studied at a few temperatures for benzene’s* and toluene*. Chao’s group at Purdue University has measured binary VLE data of hydrogen with tetralin, bicyclohexyl, quinoline, toluene, and thianaphthene3-’ at four temperatures and seven pressures. Similarly, Nasir and Kobayashi’ measured binary VLE data of hydrogen with 9methylanthracene, dibenzofuran, and 22ethylanthraquinone at numerous temperatures and pressures. Some VLE data for synthetic fuels are also available from the literature. The development of the coal liquefaction process has resulted in the measurement of VLE data for hydrogen, methane and hydrogen sulphide mixtures with coal liquids and distillate fractions of the have been liquids ‘*lo Also gas solubility measurements made for an Athabasca bitumen saturated with carbon dioxide, methane, or nitrogen”. Vapour--liquid equilibrium data for mixtures of shale oil or a shale oil fraction and methane are measured in this study. The shale oil was obtained from the Green River formation in Utah by retorting the shale using the Union B process. This study reports densities, bubble point 0016-2361/86/050663-06$3.00 (’ 1986 Butterworth & Co. (Publishers)
Ltd.
pressures, and saturated liquid volumes as a function of methane mole fraction and temperature. This type of data may be used to test existing correlations for saturated liquid densities. For example, the critical properties of the shale oil may be predicted using the generalized equation of Riazi and Daubert’* ; then a saturated liquid density correlation such as the Yen-Woodsi3, modified Rackett14, Gunn and Yamada15, or Costald equation” may be used to examine the use and accuracy of these correlations in predicting the experimental data. EXPERIMENTAL The experimental apparatus used to make the PVT measurements is shown in Figure 1. The apparatus contains many of the same features as the apparatus described by Nasir et al. 17-18. However, the principal approach is the same as that described by Sage et a/.19. The main part of the equilibrium cell is a hand-driven 1OOccRuska variable volume positive displacement pump Mode1 2200. The pump has a maximum pressure rating of 55,158 kPa, is made of A-286 stainless steel, and has a vernier scale marked in divisions of 0.01~~. The pump piston is packed with teflon chevron rings containing 20% glass; the glass increases the temperature rating of the rings to approximately 450K. These rings limit the maximum working temperature of the whole system. The main feature of this design is that the Ruska pump has been inverted to eliminate dead space volume. The inverted pump piston is driven by two steel gears. Internal system pressure is measured indirectly using a Ruska Differential Null Pressure Indicator (DPI) Model 2437, a high temperature transducer model. The maximum working pressure for the DPI is 68,948 kPa and the maximum sensitivity is 0.014 kPa. The VLE system pressure is measured by balancing the DPI to null using argon gas, and measuring the argon pressure on a 34,474 kPa Heise gauge. The Heise gauge was calibrated with a Ruska dead weight gauge model 500&701 with an accuracy of 0.04%. The Heise gauge is the limiting pressure device for the system. High pressure argon is
FUEL, 1986, Vol 65, May
663
Vapour-liquid
equilibrium
study of Green River shale oil: P. F. Meier is directly related to the volume change according to Equation (1). Next, PVT measurements were made in the following manner. The variable volume Ruska pump was screwed in manually until the system pressure was approximately 34,474 kPa; difficulty in turning the Ruska pump plus a rapid pressure rise indicated that the system was liquid full. Pressure-volume measurements were made by varying system volume in 0.5~~ increments until the pressure change with volume decreased significantly; then volume changes were increased to several cc units. In this manner, pressure-volume data were obtained over the single and two phase region. At the end of each isothermal experiment, the variable volume Ruska pump was screwed into the same system volume as the first measurement and compared with the first measured pressure. These measurements were reproduced to k 5 psi and exhibited the excellent long-term leakage behaviour of the VLE system.
Figure
1 Experimental
apparatus
used to make PVT measurements
generated with an Aminco compressor which has a maximum pressure capability of 68,948 kPa. A system over-pressure condition is controlled by an AutoclaveEngineers rupture disc. The achievement of equilibrium is aided by an EMCO (Electra-Mechanics Co.) circulating pump Model 101. The pump has a maximum working pressure of 68,948 kPa and is sealed with Kalrez O-rings. Control of the equilibrium system temperature environment is accomplished using a silicone oil bath. The oil is GE silicone oil SF 9650 with a maximum temperature limit of 533K. The clean system volume was calculated as a function of temperature using methane gas. The volume was calculated using the second-order virial equation shown in Equation (1).
RESULTS Compositional data and some properties of the shale oil and shale oil fraction are given in Table 1. The shale oil fraction is a 4.4 wt% cut of the shale oil and was obtained using a 36 mm diameter fractionation column. The bubble point pressure is often determined by taking many P-V measurements over a narrow change in volume and then obtaining the bubble point by graphical interpolation. In this study we have calculated the bubble point pressure by fitting the experimental P-V data to two polynomial equations, one for the vapour-liquid and one for the liquid-full regions, and finding the join point of the two equations using the method of splines. Splines are generally defined as a piecewise polynomials of degree n whose function values and n- 1 derivatives agree at the point they join 21. Data points w ere assigned to the single
Table 1 fraction
The second-order virial constant, b, was calculated according to the equation given by Pitzer and Cur12’ which is shown below.
Properties
and compositional
Cc. distillation wt% distilled
(2)
For methane, a critical temperature of 190.6K, a critical pressure of 4604 kPa, and an acentric factor of 0.007 were used to calculate fl at different testing temperatures. Before any testing was done on the shale oil, it was evacuated to remove dissolved air. Hydrocarbons removed from the oil as a result of this procedure were collected in a liquid nitrogen cooled trap. The removed hydrocarbons were less than 0.5 wt% of the original charge. PVT measurements were made on the sample at this point to obtain the oil density as a function of temperature. Methane was then charged to the equilibrium system using a 250~ Ruska pump to measure the volume of the methane charged. The temperature and pressure of the 25Occ Ruska charging pump were the same at the beginning and end of the addition of methane gas to the equilibrium system; thus, the molar addition of methane
664
FUEL, 1986, Vol 65, May
Oil
Fraction
260 464 573 652 720 782 845 912 992 1101” 1362”
282 346 369 385 398 411 424 434 447 463 663
_
&(0.1445+0.073~)-(0.330~0.460(7;’ ’ -(0.1385+0.500)1;-2-(0.0121+0.097~)7;~3 -o.o073oT,-s
data of the shale oil and shale oil
no Gasoline - IBP - 400’F “i Diesel - 40&650’F :6 Vacuum gas oil - 65&100O”F U’,1000°F + residue Pour point (“C) Molecular weight (gmoleei) Refractive index EIrmenral Carbon Hydrogen Nitrogen Oxygen Sulphur ’
5.4 24.9 51.7 18.0 +15 282 1.5218
UnalJses (WY%)
Obtained
83.20 10.17 2.41 2.98 0.64 by extrapolation
41.7 58.0 0.3 - 53 185 1.4661
Vapour-liquid
3zo: Mole%Methane + Shale Oil - 313.2 K 1 I
I
I
0305
83
1
Volume - CkZ
0. te 5
DecitGZs
17.8 Mole%Methane + Shale Oil - 313.2 K
20000 4 i
l!
moo0
10000
5000
0
I
I
I
t53
0.275
1
0.293
0.315
I
0.333
0.
5
Volume - Cubic Decimeters Figure 2 Isotherms . sharp phase changes Table 2
Bubble point pressures,
Temperature 294.1 313.2 348.2 383.2 423.2
depicting
(K)
raw PV data
saturated
exhibiting
obscure
and
equilibrium
study
of Green River shale
or two phase region using a graphical plot of the data as a guide. For sharp breaks between the single and two-phase region, the assignment of data points was clear. At higher mole fractions of methane, the phase transition was not sharp, and the assignment of PV data points was not clear. In these cases, data were assigned on a trial basis and then reassigned as necessary to allow convergence of the spline method. The standard error of all the data points lit to the spline method never exceeded 275 kPa; in most cases, the error was considerably less. When the spline method clearly gave an anomalous bubble point pressure, a graphical interpolation was used to obtain the density, the saturated liquid volume, and the bubble point pressure. This occurred only at the higher methane mole fractions with the unfractionated shale oil. The type of polynomial equations used to fit the vapourliquid or liquid regions were selected primarily on the basis of the adequacy of the equation to tit the data rather than theoretical reasons. In theory, if the isothermal compressibility was a constant, a plot of In (volume) versus pressure would yield a straight line; however, the isothermal compressibility is a weak function of pressure, and it was found that a quadratic in the natural log of system volume gave a better fit for the liquid phase pressure. The same equation form was used to fit the two phase PV data. The density and molar volume of the shale oils in the absence of methane were determined using an equation for pressure which was linear in the natural log of system volume. Sample isotherms depicting the raw data are shown in Figure 2for data exhibiting sharp and obscure phase changes. The advantage of the spline method is that the bubble point pressure may be obtained with a relatively small data set compared with the graphical interpolation method. A control test with methane and n-decane was used to test the ability of the equipment and spline method to accurately determine the bubble point pressure for a vapour-liquid mixture. These pressures were compared with the results of Reamer et al.” which were obtained by graphical interpolation of PV data. The bubble point pressures we determined were only 335% larger than the pressures they reported. The long-term leakage behaviour
molar liquid volumes, and densities for the shale oil as a function
Bubble point pressure _._
_
(kPa)
_
oil: P. F. Meier
Saturated
of temperature
liquid volume (dma mole- r)
and methane
mole fraction
Density
(0.300)h 0.311 0.323 0.335 0.349
(0.9405,b 0.9060 0.8743 0.8429 0.8089
313.2 3482 383.2 423.2
Shale oil+ 17.8 mole :A CH, 5364 5978 6219 6578
0.267 0.275 0.287 0.299
0.8803 0.8525 0.8177 0.7846
313.2 348.2 383.2 423.2
Shale oil + 38.3 mole “0 CH, 15823” 16892” I8092 18078
0.207” 0.216 0.225 0.236
0.8717” 0.8341” 0.8005 0.7636
313.2 348.2 383.2 423.2
Shale oil + 54.4 mole :, CH, 28 165” 28992” 3 1268” 31164
0.168” 0.175” 0.18v 0.188”
0.8 166” 0.7854 0.7652” 0.733w
’ b
These numbers were determined by graphical interpolation This number is given for comparison only. Waxes are present
(kgdm
j)
in the oil at this temperature
FUEL, 1986, Vol 65, May
665
Vapour-liquid equilibrium study of Green River shale oil: P. F. Meier of our system was also established by measuring the bubble point pressure of a 50150 mole% mixture of methane and n-decane; during a four day interval, the bubble point pressure was repeatedly determined with less than 0.1% variation. Thus the control test demonstrated the ability of the equipment and spline method to reproduce literature data obtained by graphical interpolation. Also, there was no long-term leakage of the VLE equipment. Table 2 shows densities, saturated molar liquid volumes, and bubble point pressures measured for the western shale oil as a function of temperature and methane Table 3
Bubble point pressures,
saturated
mole fraction. Table 3 shows the same properties for the shale oil fraction. Some of these data have been graphically depicted. Figure 3 shows the shale oil density as a function of temperature. The apparently anomalous behaviour of the oil density below 313K (40°C) is explained by the presence of wax in the oil. Solvent dewaxing of the oil with methyl ethyl ketone at 273K indicated that the oil contains 7.9 wt% wax; this wax begins to crystallize from solution at 305K. Figure 4 shows that solid formation is not a problem at room temperature for the shale oil fraction. The bubble point pressure is shown as a function of
molar liquid volumes, and densities for the shale oil fraction
as a function
of temperature
and methane
mole
fraction Temperature
Bubble point pressure
(K)
294.7 313.2 348.2 383.2
Saturated
(kPa)
_ _ _ _
423.2 Shale oil fraction + 23.0 mole % CH, 6695 7302 7901 8205 Shale oil fraction f43.5 mole ?< CH, 16706 17409 18078 17864 Shale oil fraction f53.3 mole Y/, CH, 22504 23559 23725 23132
313.2 348.2 383.2 423.2 313.2 348.2 383.2 423.2 313.2 348.2 383.2 423.7
liquid volume
Density
(dm3 mole-‘)
0.218 0.223 0.233 0.243 0.255
0.8492 0.8294 0.7929 0.7613 0.7240
0.186 0.192 0.199 0.209
0.7870 0.7595 0.7328 0.6976
0.146 0.153 0.159 0.169
0.7636 0.7270 0.6997 0.6608
0.129 0.135 0.141 0.147
0.7368 0.7044 0.6749 0.6462
(kgdm
“)
0.08
0.95
I
0 0-M
Legend
Legend 0
0.90
$ s $ f c3
0.0 MOM &than0
A
17.S Mole% Methane
+
38.3 MOM Mothone
0.62
0
0.0 Mold
A
23.0 Mole% Ydhano
Methane
+
43.5 LloloX Methane
X
53.3 Mole% Mothano
OJJs
0.80
0.70 0.75
0.66
0.66
0.70
do
1
Figure 3
methane
666
Temperature mole fractions
FUEL,
1986,
0.64
340
Tempemture - K
dependence
4hO
300
4
of the shale oil density at different
Figure 4
different
VOI 65, May
400
350
Temper&n, Temperature dependence methane mole fractions
450
- K
of the shale oil fraction
density at
Vapour-liquid 30000
moo0
If
20000
Y
b i 3
l’ooo
2
3 3
lx4
10000
5oo:by, ,,,
cl Denana-344.3K q Shala011- 348.2 K E shp??_!?!_~~~?!_z~_r
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
equilibrium
study
of Green River shale
oil: P. F. Meier
pressures of the methane-decane system reported by Reamer et ~1.‘~ where a much larger data set was employed in the bubble point estimation. The variable volume pump used in collecting PV data was a convenient device for varying the VLE system volume without introducing any long-term leakage effects, as shown by the reproducibility of our experimental measurements at the highest measured pressure. The temperature dependence of the crude shale oil may be compared with that for a typical crude oil using the API volume correction factor formula described by Hankinson et ~1.~~. Using this formula and the crude oil constants for relating the thermal expansion coefficient at the base temperature to the base density, the densities of the crude shale oil in Table 2 (with no methane) may be extrapolated to 288.7K (60°F). This extrapolation leads to 60’F densities of 0.9224, 0.9147, 0.9079, and 0.9025 gee- ’ for the data reported at 313.2, 348.2, 383.2, and 423.2K, respectively. Thus the thermal expansion coefficient for an average crude oil is not appropriate for the shale oil used in this study. This calculation shows one difference between shale oil and crude oil and suggests that the compositional difference between shale oil and crude oil will result in similar discrepencies for other crude oil correlations.
Methane Mole Fraction Figure 5 Bubble point pressure dependence on methane mole fraction for benzene, toluene, decane, the shale oil. and the shale oil fraction
ACKNOWLEDGEMENT The author wishes to thank Nancy K. Phillips for doing the statistical spline method data-analysis. methane mole fraction in Figure 5 for the shale oil and shale oil fraction. For comparison, the same relationship is shown for benzene2, toluene2, and decane22,23 using the data of Elbishlawi and Spencer and Sage et ~1. The small difference in temperature for the three sets of data (10K) should not be enough to alter the following comparative statements. Within the range of mole fractions shown in the figure, decane shows the highest methane solubility at a given bubble point while benzene has the lowest solubility. Thus the shale oils are bracketed by these two pure compounds in terms of solubility. The solubility of toluene is similar to the solubility for the unfractionated shale oil and the shale oil fraction has a higher methane solubility than the unfractionated shale oil. The bubble point pressure is shown as a function of temperature in Figure 6 for the shale oil fraction at two methane concentrations. This figure indicates that the measured bubble points are in the region of isobaric and the cricondenbar is retrograde condensation, bracketed in this temperature range. This phenomena was also observed for the unfractionated shale oil (see Tab/e 2) at the experiments with the two higher methane mole fractions.
ZSOOPI-
!22OOPI-
21ooaI-
K I
Fizoooa ,-
f
16000 I-
16000 ,-
l_/m___
woo0
DISCUSSION The statisitical spline method was shown to be a useful tool for calculating the bubble point pressure, density, and saturated liquid volume of a vapour-liquid system. This method, using a limited data set from our experimental apparatus, accurately determined the bubble point
1.000
+
--------------
300
350
4
Tempemture Figure 6 Bubble point pressure shale oil fraction at two methane
IO
-;
dependence on temperature mole fractions
FUEL, 1986, Vol 65, May
for the
667
Vapour-liquid
equilibrium
study of Green River shale oil: P. F. Meier
REFERENCES 1 2 3 4 5 6 I 8 9 10
668
Schoch, E. P., Hoffman, A. E., Kasperik, A. S., Lightfoot, J. H. and Mayfield, F. D. Ind. Eng. Chem. 1940, 32(6), 788 Elbishlawi, M. and Spencer, .I. R. Ind. Eng. Chem. 1951, 43(8), 1811 Simnick, J. J., Lawson, C. C., Lin, H. M. and Chao, K. C. AIChE .I. 1977, 23, 469 Sebastian, H. M., Yao, J., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data 1978, 23, 167 Sebastian, H. M., Simnick, J. J., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data. 1978,23, 305 Simnick, J. J., Sebastian, H. M., Lin, H. M. and Chao, K. C. J. Chem. Eng. Data 1978, 23, 339 Sebastian, H. M., Simnick, J. J., Lin, H. M. and Chao, K. C. Can. J. Chem. Eng. 1978, 56, 743 Nasir, P. and Kobayashi, R. J. Chem. Eng. Data 1981, 26, 321 Lin, H. M., Sebastian, H. M., Simnick, J. J. and Chao, K. C. Ind. Eng. Chem. Process Des. Dev. 1981, 20, 253 Wilson, G. M., Johnston, R. H., Hwang, S. C. and Tsonopoulos, C. Ind. Eng. Chem. Process Des. Deo. 1981, 20, 94
FUEL, 1986, Vol 65, May
11 12 13 14 15 16 17 18 19 20 21 22 23 24
Svrcek, W. Y. and Mehrotra, A. K. J. Can. Petroleum Tech. 1982, July-August, 31 Riazi, M. R. and Daubert, T. E. Hydrocarhotl Processing 1980, March, 115 Yen, L. C. and Woods, S. S. AIChE J. 1966, 12,95 Rackett, H. G. J. Chem. Eng. Data 1970, 15, 514 Gunn, R. D. and Yamada, T. AIChE J. 1971, 17, 1341 Hankinson, R. W. and Thomson, G. H. AIChE J. 1979,25,653 Nasir, P., Martin, R. J. and Kobayashi, R. Fluid Phase Equilibria 1981, 5, 279 Nasir, P., Ph.D. Dissertation, Rice University, 1980 Sage, B. H.. Schaafsma, J. G. and Lacey, W. N. Ind. Eng. Chem. 1934, 26, 1218 Pitzer, K. S. and Curl, R. F. Jr. J. Am. Chem. Sot. 1957, 79, 2369 Smith, P. L. The American Statistician 1979, 33, 57 Reamer, H. H., Olds, R. H., Sage, B. H. and Lacey, W. M. Ind. Eng. Chem. 1942, 34, 1526 Sage, B. H., Lavender, H. M. and Lacey, W. N. Ind. Eng. Chem. 1940, 32, 743 Hankinson, R. W., Segers, R. G., Buck, T. K. and Gielzecki, F. P. Oil and Gas J. 1979, December 24, 66