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Chapter 21
Crude Oil Properties and Condensate
Properties and Correlations
Paul Buthod, U. of Tulsa*
Introduction
All crude oils are composed primarily of hydrocarbons,
which are made by the combination of the elements car-
bon and hydrogen. In addition, most crudes contain
sulfur compounds and trace quantities of oxygen,
nitrogen, and heavy metals. The difference in crude oils
is caused by the amount of sulfur compounds and by the
types and molecular weights of the hydrocarbons making
up the oil.
The hydrocarbons found in crude oil range in size from
the smallest molecule, methane, which contains 1 atom
of carbon, to the largest ones, which contain nearly 100
atoms of carbon. The types of hydrocarbon compounds
are paraffin, naphthene, and aromatic, found in raw
crude, and olefin and diolefin, which are sometimes
found in refined products after thermal treatment. Since
any crude oil will have several thousand different com-
pounds in it, it has been impossible so far to develop ex-
act analyses of the actual compounds present. Three
methods of reporting analyses are available-ultimate
analysis, chemical analysis, and evaluation analysis.
Ultimate analysis lists the composition in percentages
of the elements carbon, hydrogen, nitrogen, oxygen, and
sulfur. This tells very little about the type of compounds
present or the physical characteristics of the oil. It is
useful, however, in determining the amount of sulfur
that must be removed. Table 21.1 shows the ultimate
analysis of several crude oils.
Chemical analysis gives composition in percentage of
paraffin, naphthene, and aromatic-type compounds pres-
ent in the crude. This type of analysis can be determined
with fair accuracy by means of chemical reaction and
solvency tests. An analysis of this sort gives an idea of
the usefulness of refined products but does not give any
‘This author also wrote the tiginal chapter on this topic in the 1962 edation.
means of predicting the amount of various refined prod-
ucts. Table 2 1.2 gives the chemical analysis of several
fractions of four crude oils.
The crude-oil evaluation consists primarily of a frac-
tional distillation of the oil followed by physical-
property tests (for parameters such as gravity, viscosity,
and pour point) on the distillation products. Since the
primary means of separating products in the refinery is
fractionation, this analysis makes it possible to predict
yields of refined products and physical properties studied
in the evaluation. The evaluation curves shown in Fig.
2 1.1 make it possible to predict the physical properties of
the refined products. As an example of the use of evalua-
tion curves, Table 2 1.3 shows product yields and proper-
ties when a refinery is operated for maximum gasoline
yield, and Table 2 1.4 shows product yields and proper-
ties when the objective is to produce lubricating oils and
diesel fuel.
Since the early 1970’s, much research has-been per-
formed on the use of the gas chromatograph to generate
simulated distillations. This has the advantage of produc-
ing crude-oil evaluation curves with very small samples
of crude and in a period of about an hour, compared with
about a gallon of crude for a fractional distillation col-
umn and about 2 days for the analysis. The simulated
distillation is called ASTM Test Method D2887. I
Base of Crude Oil
Since the beginning of the oil industry in the U.S., it has
been convenient to separate crude oils into three broad
classifications or bases. These three, paraffin, in-
termediate,
and naphthene, are useful as general
classifications but lead to ambiguity in many instances.
Because a crude may exhibit one set of characteristics for
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21-2
PETROLEUM ENGINEERING HANDBOOK
TABLE Pl.l-ULTIMATE CHEMICAL ANALYSES OF PETROLEUM
Specific
Component
Gravity
Temperature
WI
Petroleum
-r
PC)
C H
N 0 S
- -
-- -
Pennsylvania pipeline
0.862 15
85.5 14.2
Mecook, WV
0.897
0 83.6 12.9
3.6
Humbolt, KS 0.912 85.6 12.4 0.37
Healdton, OK
85.0 12.9
0.76
Coalinga, CA
0.951 15
86.4 11.7
1.14 0.60
Beaumont, TX
0.91
85.7 11.0
2.61 l 0.70
Mexico
0.97 15
83.0 11 .o
1.7*
4.30
Baku, USSR
0.897
66.5 12.0
1.5
Colombia, South America
0.948 20
65.62 11.91
0.54
‘Combined mtrogen and oxygen.
TABLE 21.2-CHEMICAL ANALYSES OF PETROLEUM, %
Grozny Grozny (“Paraffin-
Oklahoma
California
(“High Paraffin”)
Free Upper Level”),
(Davenport),
(Huntmgton Beach),
Fraction 45.3% at 572OF
(“0
Aromatic Naphthene Paraffin
140 to 203
3 25
72
203 to 252
z 30
65
252 to 302
35
56
302 to 392
14 29
57
392 to 482
18 23
59
482 to 572
17
22
61
40.9% at 572OF
Aromatic Naphthene Paraffin
4
31 65
8
40 52
13
52 35
21
55
24
26
63
11
35 57 8
64% at 572OF
Aromatlc Naphthene Paraffin
5
21 73
7
28 65
12
33 55
16
29 55
17
31 52
17
32 51
Base
paraffin
paraffin
mixed
mixed
naphthene
naphthene
naphthene
34.2% at 57Z°F
Aromatic Naohthene Paraffin
-A
i 316 656
11 64 25
17 61 22
25 45 30
29 40 31
TABLE 21.3-EVALUATION WHEN OPERATING PRIMARILY FOR GASOLINE’
Material
Gas loss
Straight-run gasoline (untreated)
Catalytic charge
V&breaker charge or asphalt
Crude oil
Percent Distilled
Gravity
Basis
Range
Midpoint Yield (OAPI) Other Properties
~-
0 to 1.3 1.3
54.5 octane number
1.3
to 32 16.6 30.7 56” 390DF ASTM endpoint7
900°F cut 32 to 80.5 56.2 48.5 28.8 165OF aniline point or 47.5
diesel index
remainder 80.5 to 100 19.5
6.4 110 penetration
100.0 32.0 11.65 characterization factor
‘Topping follwed by YaWUrn flashing to produce a gas 011 or catalflic cracking.
The
Cycle stcck IrOm catalytic cracking is thermally c racked along wtth the asphalt or vis-
breaker chargestock.
“Average gravity from nstantaneouscurve of API gravity.
?At about 400aF endpoint t he truebOiling.pCint cut point is about 2PF higher than the ASTM end point
*By a material balance.
TABLE 21.4-EVALUATION WHEN OPERATING PRIMARILY FOR LUBRICATING-OIL STOCK0
Percent Distilled
API
Material
Viscosity,
Basis
Range Midpoint Yield Gravity SU’S Other Properties
Gas loss 0 to 1.3
-13
Light gasoline
(untreated)
300 EPb
1.3 lo
21.0 10.5 19.7
61.2C 63.8 octane numberd
Reforming naphtha
445 EPb
21 .O to
38.5 29.7 17.5
41.3e 0.16% sulfur
Diesel fuel
156 aniline point
38.5 to
56.5 47.5 18.0
32.1
Light lube or cracking stock
41 (estimated) 50 diesel
Index; 0.82% sulfur
remainder
56.5 to
74.9 65.7 18.4
25.9 145 at 100°F 1.49% sulfur’
Lube stock (untreated)
100 W’s viscosity
at 2lOOF 74.9 to
80.9 77.9 6.0
19.1 100 at 210°F
Asphalt
100 penetration
80.9 to
100.0 19.1
100 penetration at 77OFg
Crude oil
100.0
32.0
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-3
TABLE 21.5-BASES OF CRUDE OILS’
API Gravity Approximate UOP* *
at 60°F
Characterization
Factor
Low-Boiling High-Boiling Key Fraction Key Fraction Low- High-
Part Part 1
2
Boiling
Boiling
paraffin paraffin 40+ 30+ 12.2+ 12.2+
baraff
n
intermediate
paraffin naphthene
intermediate
paraffin
intermediate
intermediate
intermediate naphthene
naphthene
intermediate
naphthene
paraffin
naphthene
naphthene
‘USBM, Repon 279 (Sept. 935).
“Universal Oil Products Co.. Chicago
40+
40+
33 to 40
33 to 40
33 to 40
33-
33-
33-
its light materials and another set for the heavy-lube frac-
tions, the USBM has developed a more useful method of
classifying oils.
Two fractions (called “key fractions”) are obtained in
the standard Hempel distillation procedure. Key Fraction
1 is the material that boils between 482 and 527°F at at-
mospheric pressure. Key Fraction 2 is the material that
boils between 527 and 572°F at 40 mm absolute
pressure. Both fractions are tested for API gravity, and
Key Fraction 2 is tested for cloud point. In naming the
type of oil, the base of light material (Key Fraction 1) is
named first, and the base of the heavy material (Key
Fraction 2) is named second. If the cloud point of Key
Fraction 2 is above 5”F, the term “wax-bearing” is add-
ed. If the pour point is below 5”F, it is termed “wax-
free.”
Thus,
“paraffin-intermediate-wax-free” would mean
a crude that has paraffinic characteristics in the gasoline
portion and intermediate characteristics in the lube por-
tion and has very little wax. Table 21.5 shows the
criteria used in establishing bases of oil by the USBM
method.
Several attempts have been made to establish an index
to give a numerical correlation for the base of a crude oil.
The most useful of these is the characterization factor K
developed in Ref. 2,
3K=-
Y ’
in which TB is the molal average boiling point (degrees
Rankine) and y is the specific gravity at 60°F. This has
been used successfully in correlating not only crude oils,
but refinery products both cracked and straight-run.
Typical numerical values for characterization factors are
listed in Table 2 1.6.
In addition to the relationship between the
characterization factor and the specific gravity and boil-
ing point defined above, a number of other physical
properties have been shown to be related to the chamc-
terization factor. Among these properties are viscosity,
molecular weight, critical temperature and pressure,
specific heats, and percent hydrogen.
Table 21.7 shows characterization factors for a
20 to 30
20-
30+
20 to 30
20-
20 to 30
30+
20-
12.2+ 11.4 to 12.0
12.2 + 11.4-
11.5 12.0o 12.2+
11.4 12.1o 11.4 to 12.1
11.4 12.1o 11.4-
11.5- 11.4 to 12.1
11.5- 12.2+
11.4- 11.4-
TABLE 21.6-TYPICAL CHARACTERIZATION
FACTOR VALUES
Product
Characterization
Factor
Pennsylvania stocks (paraffin base)
12.1 to 12.5
Mid-Continent stocks (intermediate)
11.8 to 12.0
Gulf Coast stocks (naphthene base)
Cracked gasoline
Cracking-plant combined feeds
Recycle stocks
Cracked residuum
11 .o to 11.6
11.5 to 11.8
10.5 to 11.5
10.0 to 11.0
9.8 to 11 O
number of worldwide crudes and products and typical
hydrocarbon compounds that have the same character-
ization factor as the oil in question.
Physical Properties
Fig. 21.2 shows the relationship of carbon-to-
hydrogen ratio, average molecular weight, and mean
average boiling point as a function of API gravity and
characterization factor. The API
Technicalata ook3
has published a number of correlations for physical prop-
erties of petroleum. For the most accurate data, this
reference should be consulted.
When oil is heated or cooled in a processing operation,
the amount of heat required is best obtained by the use of
the specific heat. Fig. 21.3 shows the specific heat of
liquid petroleum oils as a function of API gravity and
temperature. This chart is based on a characterization
factor of 11.8, and if the oil being studied is other than
that, there is a correction shown at the lower right side of
the chart. The number obtained for the specific heat
should be multiplied by this correction factor. Certain
paraffin hydrocarbons are also shown on the chart. No
correction need be applied to these.
If vaporization or condensation occurs in a processing
operation, the heat requirements are most easily handled
by the use of total heats. Fig. 2 1.4 gives total heats of
petroleum liquid and vapor, with liquid at 0°F as a
reference or zero point. This eliminates the necessity of
selecting a latent heat, specific heats of both vapor and
liquid, and deciding at what temperature to apply the la-
tent heat. Certain corrections must be applied for
characterization factor and for pressure.
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21-4
PETROLEUM ENGINEERING HANDBOOK
TABLE 21.7-CHARACTERIZATION FACTORS OF A FEW HYDROCARBONS, PETROLEUMS, AND TYPICAL STOCKS
Characterization
Factor Hydrocarbons Typical Crude Oils Miscellaneous Products
14.7
14.2
13.85
13.5 to 13.6
13.0 to 13.2
12.8
12.7
12.6
12.55
12.5
12.1 to 12.5
12.2 to 12.44
12.0 to 12.2
11.9 to 12.2
propane
propylene
isobutane
butane
butane-l and isopentane
hexane and tetradecened
P-methylheptane and tetradecane
pentene-1, hexene-1, and cetene
2,2,4-trimethylpentane
hexene-2 and 1.3-butadiene
2,2,3,3tetramethyl butane
2,l l-dimethyl dodecadiene
11.9
11.8 to 12.1
11.85
11.7 to 12
11.75
11.7
11.6
11.5 to 11.8
11.5
hexylcyclohexane
butylcyclohexane
octyl or diamyl benzene
11.45 ethylcyclohexane and 9-hexyl-l l-methylheptadiene
11.4 methylcyctohexane
11.3to 11.6
11.3 cyclobutane and 2,6,10,14tetramethyl hexadiene
Cotton Valley (LA) lubes
Pennsylvania-Rodessa (LA)
Big Lake (TX)
Lance Creek (WY)
Mid-Continent (MC.)
Oklahoma City (OK)
Fullerton (W. TX)
Illinois; Midway (AR)
W. TX; Jusepin (Venezuela)
Cowden (W TX)
Santa Fe Springs (CA)
Slaughter (W. TX); Hobbs (NM)
Colombian
Hendrick and Yates (W. TX)
Elk Basin, heavy (WY)
Kettleman Hills (CA)
Smackover (AR)
Lagunillas (Venezuela)
Gulf Coast light distillates
‘12.66 (range 12.1 to 13.65) calculated rom factors of raw and dewaxed ube stocks
‘\ / (YIELD1
94.5 API adsorption gasoline
Four Venezuelan paraffin waxes
paraffin wax*: MC. 82.2 API natural gasoline
CA 81.9 API natural gasoline
debutanized E. TX natural gasoline
San Joaquin (Venezuela) wax distillate
Panhandle (TX) lubes
Six Venezuelan wax distillates
paraffin-base gasolines
Middle East light products
cracked gasoline from paraffinic feeds
E. TX gas oil and lubes
light cycloversion gasoline from M.C. feeds
Middle East gas oil and lubes
cracked gasoline from intermediate feeds
E. TX and IA white products
cracked gas oil from paraffinic feeds
catalytic cycle stocks from paraffinic feeds
cracked gasoline from naphthene feeds
Tia Juana (Venezuela) gas oil and lubes
naphthenic gasoline: catalytic (cracked)
gasoline
catalytic cycle stocks from MC. feeds
cracked gasoline from hrghly naphthenrc feeds
high-conversion catalytic cycle stocks from
parafbnic feeds
typical catalytic cycle stocks
liaht-ail coil thermal feeds
catalytic cycle stocks from
11.7~characterization-factor feeds
gasoline from catalytic re-forming
*.- , , 1 I I I I ,
IO
20 30 40 50 60 i-0 80 90 100”
+
PERCENTAGEDISTILLED
I I
Ftg. 21 .l-Evaluation curves of a 32.0°API intermediate-base
crude oil of characterization factor 11.65.
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21-6
PETROLEUM ENGINEERING HANDBOOK
m
7
/
L
o-
o-
o-
o-
9
3-
34
0
I i I I I I
I I I I I
I I I I I I I I
III I
0
200 400 600 000
TEMPERATURE,“F
Fig. 21.3-Specific heats of Mid-Continent liquid oils with a cor-
rection factor for other bases of oils.
1,., ,,,,,,.,
=CHARACTEklZATION ACTOR
3MOLAL AVG. BOILING POINT,“R
- / SPEClF(CG.,ilTYf~
/
I
I I
I
I 000
900
, OF
1,000 1,100 1,200
Fig. 21.4-Heat content of petroleum fractions including the effect of pressure.
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-7
Gravity, API
Sulfur, %
Viscosity, SUS at lOOoF
Date
Characterization factor
At 25O“F
At 450°F
At 550°F
At 750DF
Average
Base
Loss, %
Gasoline
% at 300°F
Octane number, clear
Octane number, 3 cc TEL
% to 400°F
Octane number, clear
Octane number, 3 cc TEL
% to 450°F
Quality
Jet stock
% to 550°F
API gravity
Qualitv
TABLE 21.8-TRUE-BOILING-POINT CRUDE OIL ANALYSES
Location
Kerosene distillate
%, 375 to 500°F
API gravity
Smoke point
Sulfur, %
Quality
Distillate or diesel fuel
%, 400 to 700°F
Diesel index
Pour point
Sulfur, O/O
Quality
Cracking stock (distilled)
%, 400 to 900°F
Octane number (thermal)
API gravity
Quality
Cracking stock (residual)
% above 550°F
API gravity
API cracked fuel
% gasoline (on stock)
% gasoline (on crude oil)
Lube distillate (undewaxed)
% 700 to 900°Fc
Pour point
Viscosity index
Sulfur, %
Quality
Residue, % over 900°F
Asphalt quality
Atlanta,
Smackover, AR
AR
20.5
2.30
270
413139
11.62
11.82
11.48
12.05
11.47
12.08
11.55 12.25
11.53 12.05
I IP
0 1.5
6.0
73.2a
a9.0a
11 .o
66.0b
25.2d
14.4
good b
39.2d
48.5b
45.3d
24.1
41.9
good
56.3d 6.1 d
57.4
29.5b
9.5
38.0
16.0b
0.29b
15.0d
46.0
27.0b
0.06b
excellent
29.2
35.0d 19.7d 23.8
38.4d 28.0d
43.0b 76.0d mob
33.0 33.0b 48.5”
Ob
high
- 30.0b - 3.0 -25.ob
20.0b
0.82 b 0.15b 0. 8b 2.56
0.35b 0.W’
48.2 51.4d
71.4b 64.5 b
25.7
35.5
75.9 42.2d
14.7 27.1
4.8 9.6
35.5 54.9
27.0 23.2
19.0
16.4d 22.2d
37.0b
2.45 b
40.8
good
113.0b
0.8b
excellent
7.9d
1.5b
57.0d
excellent
(limestone)
44.5
0.48c
35
Kern
River,
CA
10.7
1.23
6,000 +
11.13
11.15
11.15
N
0
0
1.2d
2.P
2.7d
32.5d
13.0b
0.38b
41.8d
7.5.6b
20.0
good
93.9d
9.1
a Simply aviation gasoline, not always 300-F cut point
’ Esbmated from general cotrelat~ons.
‘Sour oils (1.e.. oils containing more than 0.5 cu ft hydrogen sulfide per 100 gal before stabilization.)
dApproximat.+d from data on other fractions of same oil.
‘Research method Octane number
Santa
Maria,
CA
15.4
4.63
368
812154
Coalinga
(East),
CA
20.7
0.51
178
Coalinga,
CA
31.1
0.31
40
11.90
11.42
11.29
11.11
11.48
IN
0
11.28
11.20
11.23
N
3.0
11.5
11.53
11.59
11.72
11.58
I
1.1
7.0 1.2d
21 .6d
72.ob
13.2
59.8e
70.30
17.0
9.6d 31 .6d
67.0 b 66.7b
15.6d
35.6d
good b excellent b
25.0
43.0
good
8.5
34.5
1.8d
29.3d
36.9
46.2d
46.0d
good
16.0d Il.Od
34.0d 37.0
14.5b 17.0b
o.ub
0.06b
39.8
75.6d
22.8
59.46
22.3
excellent
45.6d
70.4b
28.0
good
75.0
i::
15.0
11.0
16.0
67.7d 52.P
11 .o 18.2
4.2
5.0
27.5 42.2
18.6 22.2
13.06 17.6d
0.67b
56.0b
0.43b
47.0
28.0d
21.7d
excellent excellent
good
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21-8
PETROLEUM ENGINEERING HANDBOOK
Sampling pressure
Sampling temperature
Total fluid mol wt
Liquid/gas ratio,
bbl per million scf
Gas mol WI
Gas analysis, mol%
Carbon dioxide
Nitrogen
Methane
Ethane
Propane
i-butane
n-Butane
i-pentane
n-Pentane
Hexanes
Heptane plus
Liquid gravity, OAPI
Llquld mol wt
Liquid analysts
Light gasoline
Naphtha
Kerosene dtstlllate
Gas oil
Nonviscous lube
Residuum and loss
TABLE 21.9-ANALYSIS OF CONDENSATE LIQUID AND GAS FROM SELECTED TEXAS ZONES
Chapel Hill
Palusy
Zone
645
Carthage
Upper
Carthage Old Ocean Old Ocean
Pettite Lower Pettile
Chenault Larson Seellgson
Seeligson
Zone Zone Zone Zone
21 D Zone 21 A Zone
Saxet
607 632- 752 702 810 410 1087
82 70
67
85 85 80
85
25.03 19.62 20.19
20.76 20.51 20 64
20.63
88
21.34
88.74 16.23 29.28 29.33 28.71
29.88 24.48
41.33
20.18 18.25 18.25 18.70 18.17 18.42
18.69 18.89
0.794 0.695 0.646 0.448
0.468 0.130
0.200 0.299
1.375 1.480
1.967
0.370 0.414
0 075 0.253
0.281
76.432 89.045 88.799 87.584 90.162
89.498 88.731
86.733
7.923 4.691 3.363 5.312
4.067 4 555 5.224
4.816
4.301
1.393 1.536 2.302
1.616 1 909 1.795
2.873
1.198 0.401 0.335 0.584 0.464
0 465 0.488
0.836
1.862 0.394 0.583 0.630 0.390 0 493
0.452
0.788
0.937 0.283
0.302
0.416
0.274
0.286
0.172
0.583
0.781 0.191 0.254 0.207 0.123 0209
0.241
0.256
1.415 0.379 0.574 0.505 0.418 0 385
0.414
0.633
2.992 1.098 1.641 1.642 1.604
2015 2.032
2.102
Total 100.00 100.00 100.00 100.00 100 00
100.00 100.00
10000
71.8
61.0
64.8
54 0
47.6
52.7
52.1 60.0
68.64 91.51 81.55 85.93 110.07 94.49 103.22 68.73
Vol % OAPI Vol % OAPI
---__
55.1 82.9 29.1 74.8
37.2 60.5 48.4 59 2
21.1 50.8 18.2 48.1
5.6 4.3
4.4
Vol % “API
40.7 76.6
47.0 59.3
7 9 47.6
Fig. 21.5-Approximate relation between viscosity, tempera-
ture, and characterization factor.
Vol %
‘=APl Vol % “API Vol % OAPI Vol % ‘API Vol % OAPI
---
21.2 71.2 14.7 70.9 22.6
70.1 20.7 68.4 35.7 73.6
55.3 52.9 36.9 52.2 47.7 53.4 49.5 53.1
47.6
55.9
15.0 42.6 17.4 42.1
15.9 43.8 16.1
43.0 10.0 44.9
3.8 37.8 21.3 36.6 7.3 37.4 7.2
37.0
2.4 38.2
7 4 29.8
4.7
2.3 6.5
6.5 4.3
An important physical property of petroleum
necessary in studying flow characteristics is viscosity.
Viscosity of petroleum is often reported in Saybolt
Universal Seconds (SUS), derived from one of the com-
mon routine tests for oils. For engineering calculation,
however, the viscosity should be obtained in centipoise.
The relation between these two systems, according to the
U . S Bureau of Standards, is
149.7
5 =0.219ts” --,
Yo
tsu
where
FL0
= viscosity, cp
Yo
= specific gravity of oil at measured
temperature, and
tSU
= Universal Saybolt viscosity, seconds.
An accurate correlation for viscosity is difficult,
especially for viscous oils, but an estimate of viscosity
may be obtained from Fig. 21.5. Four characterization
factors are given, and interpolation must be made for
other factors.
True-Boiling-Point Crude-Oil Analyses
A number of true-boiling-point crude-oil analyses are in-
cluded in Table 21.8. In addition to the gravity, viscosi-
ty, sulfur content, and characterization factor, there is a
breakdown of typical products made from each crude.
This table may be used either to estimate the value of the
products listed or to plot and evaluate any set of products
obtained (see Fig. 21.1). The table is separated first ac-
cording to state, and within each group according to
gravity.
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-9
When the quality of a product is indicated as good or
excellent, it means not only that the quality is good but
that it is present in normal amounts and that a salable
product can be made without excessive treatment.
Table 21.9 shows the analysis of the gas and liquid
phases after a stage separation of several condensates.
Nelson4 gives a compilation of 164 crudes and lists
the gravity, characterization factor, sulfur content, and
viscosity of each. Those tables include yields of typical
refined products, along with their physical properties and
an indication of their quality. A true-boiling-point curve
can be generated by plotting the end points of these prod-
ucts against the cumulative volume percent yield. If the
characterization factor is plotted on the same graph, the
characterization factor at any instantaneous boiling point
can be calculated. When instantaneous temperatures and
characterization factors at different percents are known,
specific gravity, API gravity, and viscosity curves may
be estimated. Thus, evaluation curves such as those in
Fig. 21 .l may be produced for any of the 164 crudes
listed. A typical page of these data is shown in Table
21.8.
More recently, a series on evaluations of non-U.S.
crude oils was published. 5 The format is similar to those
in Nelson’s compilation, 4 but the physical properties are
usually more complete. An example of an analysis from
this series is shown in Table 21.10.
The USBM in Bartlesville, OK, began making distilla-
tion analyses before 1920. This laboratory [U.S. DOE
Bartlesville Energy Technology Center (BETC)] has
continued to evaluate crude oil up to the present time and
has two publications6,7
that show the distillation data
along with gravity and viscosity of the distilled fractions.
They also show the percentage composition of the frac-
tions in terms of paraffins, naphthenes, and aromatics.
This set of tables uses the correlation index rather than
characterization factor as a correlating number. In
general, low correlation index (1,) numbers indicate
highly paraffinic (pure paraffin hydrocarbons, I, =O).
High numbers indicate a high degree of aromaticity
(benzene, I,. = 100). The correlation index is defined as
follows.
1,=413.7 y-456.8+87552/T~,
where y is the specific gravity of the fraction at 60°F and
T, is the
average
normal boiling point in degrees
Rankine .
All U.S. DOE analysis data have been built into the
BETC Crude Oil Analysis Data Bank.8 The
data
retrieval system, Crude Oil Analysis System (COASYS),
is available by telephone hookup, and customers may
search, sort, and retrieve analyses from the file. More
than 30 keywords are available for searching; for exam-
ple, YEAR, APIG, LOC, GEOL and SULF, allow a search on
year analyzed, API gravity, location by state and coun-
try, geological formation, and percent sulfur in the oil,
respectively. Table 21.11 shows the type of information
obtained in a typical analysis retrieved from a computer
search by COASYS.
Bubblepoint Pressure Correlations*
In the study of reservoir flow properties, it is important
to know whether the fluid in the reservoir is in the liquid,
‘The rematnder of this chapter was written by M.0 Standing in the 1962 editon.
TABLE Pl.lO-TYPICAL CRUDE OIL EVALUATION,
EKOFISK, NORWAY
Crude
Gravity, “API
Basic sediment and water, vol%
Sulfur, wt%
Pour test, OC
Viscosity, SUS at lOOoF
Reid vapor pressure, psi at 1OO°F
Salt, lbm/l,OOO bbl
Nitrogen compounds and lighter,
~01%
Gasoline
Range, OF
Yield, VOWI
Gravity, OAPI
Sulfur, wt%
Research octane number, clear
Research octane number, - 3 mL tetraethyl
lead per gallon
Gasoline
Range, OF
Yield, ~01%
Gravity, OAPI
Paraffins, ~01%
Naphthenes. vol%
Aromatics, ~01% (0 + A)
Sulfur, wt%
Research octane number, clear
Research octane number, + 3 mL tetraethyl
lead per gallon
60 to 400
31.0
60.1
56.52
29.52
13.96
0.0024
52.0
76.0
Kerosene
Range, OF
400 to 500
Yield, ~01%
13.5
Gravity, OAPI
40.2
Viscosity, SUS at lOOoF
32.33
Freezing point, OF -38
Aromatics, VOW (0 + A)
13.1
Sulfur, wt%
<0.05
Aniline point, OF
146.2
Smoke point, mm
21
Liaht Gas Oil
Range, OF
500
to
650
Yield, ~01%
15.7
Gravity, OAPI
33.7
Viscosity, SUS at lOOoF
43.83
Pour point, OF
-25
Sulfur, wt%
0.11
Aniline point, OF
164.3
Carbon residue, Ramsbottom, wt%
0.08
Cetane
index
56.5
TopPed Crude
Range, OF
Yield, ~01%
Gravity, OAPI
Viscosity, SUS at 122OF
Pour point, OF
Sulfur, wt%
Carbon residue, Ramsbottom, wt%
Nickel, vanadium, ppm
650 +
38.8
21.5
80.25
-85
0.39
4.0
5.04, 1.95
36.3
1 o
0.21
+20
42.40
5.1
14.5
1.0
60 to 200
10.7
77.2
0.003
74.4
90.0
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21-10
PETROLEUM ENGINEERING HANDBOOK
TABLE 21.11-ADAPTATION OF BETC COMPUTER SEARCH PRINTOUT
Crude Petroleum Analysis: BETC Sample-B75008
lndentification
Webb W Field, Grant County, OK
Red Fork, Des Moines, Middle Pennsylvanian-4,464 to 4,482 ft
General Characteristics
Gravity, specific [OAPI]
Sulfur, wt%
Viscosity, SUS
at 77OF
at
1OO°F
Pour point, OF
Nitrogen, wt%
Color
0.820[41.1]
0.24
42
39
<5
0.054
brownish-black
Distillation. USBM Method (First droo at 79OF)
Stage l-Distillation at Atmospheric Pressure 746 mm Hg
Gravity at
Fraction Cut Cumulative
6OOF
Refraction
Viscosity Cloud
Correlation Index Specific at lOOoF point
wwo
Number (OF) Vol%
VOW0 Specific API Index at 20°C Dispersion
(SW
(OF) Residuum Crude
-122 -1.5
~~-
1 1.5
0.639 89.9
79.7 7
1.38560 126.3
67.2 17
1.39755 131.1
60.2 21 1.41082
133.0
55.4 22 1.42186
134.0
51.6 23
1.43039
134.7
48.8 22 1.43770
135.2
45.8 23 1.44415
135.5
42.8 24
1.45102 137.6
40.4
25 1.45771 138.0
2 167 2.2 3.7
0.670
3 212 5.5 9.2
0.712
4 257 7.4 16.6
0.738
5 302 5.8
22.4 0.757
6 347 6.7
29.1 0.773
7 392 6.0 35.1 0.785
8 437 59
41.0 0 798
9 482 6.8
47.8
0.812
10
527
5.1 52.9 0.823
Stage 2-Distillation continued at 40 mm Hg
11 392 7.2
12 437 6.2
13 482 5.6
14 527 4.8
15 572 5.1
Restduum
Carbon
Sulfur
Nitrogen
17.0
Approximate Summary
Light gas 9.2
Gas+ Naoh 35.1
Kerosend
Gas oil
Non viscous
lub
Med viscous
lub
Viscous lub
Restdue
Loss
17.8
11.6
10.3
6.0
1.3
17.0
1.0
60.1 0.842 38.6
66.3
0.851 34.8
72.1 0.863 32.5
76.9 0.874 30.4
82.0 0.887 28.0
99.0 0.934 20.0
0.690 73.6
0.743 58.9
0.311 43.1
0.845 35.9
0.854 to 0.875 34.3 to 30.3
0.875 to 0.890 30.3 to 27.4
0.890 to 0.894
27.4 to 26.8
0.934 20.0
vapor, or two-phase state. With crude oils, the fluid may
be subcooled liquid, but with some dissolved gas. Upon
reduction in reservoir pressure, a point where the gas
starts to come out of solution, called “bubblepoint
pressure,” is reached.
At this point the flow
characteristics change. Some of the earliest work in this
field was done by Lacey , Sage, and Kircher. 9
Several empirical correlations have been developed to
predict the bubblepoint pressure, and some of these arc
presented later.
Dewpoint-Pressure Correlations
The dewpoint, like the bubblepoint, is characterized by a
substantial amount of one phase in equilibrium with an
infinitesimal amount of the other phase. At the dew-
30 1.46481
30 1.47017
33 1.47736
35
38
141.2 40 14
145.6
48.4
i: ii
96 76
179 98
7.1
1.4
0.67
0.235
5oto 100
loot0 200
>200
point, the liquid phase is at its minimum. In general,
petroleum-reservoir systems that involve dewpoint
behavior at reservoir conditions are characterized by (1)
surface gas/oil ratios (GOR’s) greater than 6,000 cu
ft/bbl in most instances; (2) lightly colored tank oils,
usually straw-colored to light orange for reservoir
systems at 3,000 to 5,000 psi but grading to brown for
systems at 7,C00 psi and greater; (3) tank oil gravity
usually greater than 45”API; and (4) methane content
usually greater than 65 mol .
Few dewpoint-pressure correlations of reservoir
systems have been published. Sage and Olds” pub-
lished a very general correlation of the behavior of
several San Joaquin Valley, CA, systems. A correlation
developed by Organick and Golding I1 is discussed in
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-11
TABLE 21.11-ADAPTATION OF BETC COMPUTER SEARCH PRINTOUT
(continued)
Hvdrocarbon-tvpe Analvsis for Crude Petroleum Analvsis 875008
Fraction
Number
1
2
3
4
5
a
7
a
9
10
11
12
vow0 of
Specific
Crude Gravity
1.5 0.639
2.2 0.670
5.5
0.712
7.4 0.738
5.8 0.757
6.7 0.773
6.0 0.785
5.9
0.798
6.8 0.812
5.1 0.823
72 0.842
6.2 0.851
Analvsis of Naotha Fractions
Fraction
Vol% of P-N
Number Naphtha Paraffin
A
2 7.1 92.9
3 23.7 76.3
4 38.6
61.4
5 44.0 56.0
6 43.6 56.4
7 43.6 56.4
Summarv Data for Blends
Correlation
Index
-
7
17
21
22
23
22
23
24
25
30
30
Aromatics P-N *
(VOW0 f (vol% of
Fraction)
Fraction)
0.0 100.0
2.4 97.6
5.9 94.1
7.5
92.5
9.1 90.9
10.2
89.8
10.6
89.4
10.7
89.3
11.5
88.5
10.4 89.6
13.0
87.0
16.2
83.8
Correlation
Gravity
index of P-N
of P-N
-
0.639
5
0.665
13 0.702
16 0.727
17
0.746
17
0.761
16
0.772
16 0.784
17
0.796
18 0.809
22
0.825
21
0.831
Vol% of Fraction
Fraction Number Aromatic Naphthenes
Naphtha Paraffin Number of Total Rings
per mol
6.9 90.7 12 1.4 0.3 1.1
22.3 71.8 14 1.7 0.6 1.1
35.7 56.8
40.0 50.9
39.2 50.7
39.0 50.4
Naphtha Blend Gas/oil Blend
(Fractions 1
(Fractions 8
through 7) through 12)
VOW of Crude in Blend
Aromatic, VOW of Blend
Paraffin-Naphthene, vol% of Blend
Naphthene, ~01 of Blend
Paraffin, ~01% of Blend
Naphthene,
~01
of P-N in Blend
Paraffin, vol% of P-N in Blend
Naphthene Ring, wt% of P-N in Blend
Paraffin + Side Chains, ~1% of P-N in Blend
35.1 31.2
7.9 12.5
92.1 07.5
32.6
59.5
35.3
64.7
20.0 28.3
80.0 71.7
‘Parafbn-Naphtha
detail. Calculation of the dewpoint pressure by means of
the composition and equilibrium ratios is discussed in
Chap. 23.
Sage and Olds’ Correlation
Laboratory studies on five San Joaquin Valley systems
resulted in the correlation shown in Table 21.12. The
basis for the 160°F data presented in this table is shown
in Fig. 21.6. Although the five systems correlate within
themselves, it is not known how representative the cor-
relation is of systems from other fields. The data are
reproduced here more as a guide to dewpoint-pressure
behavior than as a means of estimating precise values of
dewpoints.
primarily conditions that pertain to dewpoints, and it
is
in this capacity that they will be discussed. The reader
should be aware, however, that the charts also may be
used to estimate critical pressure and temperature of the
more volatile systems. The correlation has limited
usefulness as a bubblepoint-pressure correlation because
it covers primarily high-volatility systems.
system. The short-cut method suffices for most
calculations.
Calculation of
Ts.
he molal average boiling point of
the system is defined as
Organick and Golding’s Correlation
TB=CyxTa, . . . . . . . . . . . . . . . . . . . . . . . . . . ...(l)
where y is the mole fraction and T, he atmospheric boil-
ing point.
This correlation relates saturation pressure of a system
Boiling points of the pure compounds (methane,
directly to its chemical composition by geans of two ethane, nitrogen, carbon dioxide, etc.) are listed in
generalized composition characteristics TB, the molal Chap. 20. The boiling point of the CT + fraction is taken
average boiling point, and W,, a modified weight as the Smith and Watson I2 mean average boiling point
average equivalent molecular weight. The saturation (MABP). The MABP can be calculated from the ASTM
pressure may be either bubble-point pressure, dewpoint
distillation curve, the procedure being first to calculate
pressure, or the very special case of critical pressure.
the ASTM volumetric average boiling point (VABP, “F)
The 15 working charts (Figs. 21.7 through 21.21) cover
and then to apply
a
correction factor to obtain the
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21-12
PETROLEUM ENGINEERING HANDBOOK
TABLE Pl.lZ--RELATION OF DEWPOINT PRESSURE OF
CALIFORNIA CONDENSATE SYSTEMS
Tank-Oil
Gravity
(“API)
lOOoF
52
54
56
58
60
62
64
16OOF
52
54
56
58
60
62
64
220°F
GOR (cu ft/bbl)
15,000 20,000 25,000 30,000
4,440 4,140
3,000 3,680
4,190 3,920 3,710 3,540
3,970 3,730 3,540 3,390
3,720
3,540 3,380 3.250
3,460 3,340
3,220 3,100
3,290 3,190 3,070 2,970
3,080 3,010 2,920 2,840
4,760 4,530 4,270 4,060 3,890 3,650
4,400 4,170 3,950 3,760 3,610 3,490
4,090
3,890 3,690 3,520 3,380 3,270
3,840 3,650
3,470 3,320
3,200 3,110
3,610 3,430 3,280 3,150 3,040 2,960
3,390 3,240 3,100 2,990 2,090 2,810
3,190
3,060 2,930 2,820 2,740 2,670
54
4,410 4,230
4,050 3,890 3,750 3,620
56
3,990 3,780 3,600 3,440 3,300 3,180
58 3,700 3,480 3,280 3,110 2,970 2,850
60
3,430 3,210
3,030 2,880 2,760 2,660
62 3,150 2,970 2,800 2,670 2,570 2,480
64
2,900
2,740 2,590 2,470 2,380 2,300
35,000 40,000
-~
3,530 3,420
3,410 3,310
3.280 3,180
3,140 3,060
3,010 2,930
2,880 2,800
2,770 2,700
TABLE 21.14-VALUES OF
EQUIVALENT MOLECULAR
WEIGHTS FOR NATURAL-
GAS CONSTITUENTS
Methane 16.0
Ethane 30.1
Propane 44.1
i-butane 54.5
n-Butane 58.1
i-pentane 69.0
n-Pentane 72.2
Hexanes 85
Ethylene 26.2
Nitrogen
28.0
Carbon dioxide 44.0
Hydrogen sulfide 34.1
MABP. The VABP is the average of the temperatures at
which the distillate plus loss equals 10, 30, 50, 70, and
90 by volume of the ASTM charge, that is,
y, = TlOW + T30% + Tsox + T70% + T90%
5
) . . . .
(2)
where TI/ is the ASTM volumetric average boiling point.
The correction to add to TV to obtain the mean average
boiling point is given in Table 2 1.13 as a function of TV
and the slope of the ASTM curve between the 10 and
90 distilled points. In the correlation, r, is in degrees
Rankine (i.e., “F+460).
Calculation of W,. The modified weight average
equivalent molecular weight, W,, is a more complex
function to evaluate. It is defined as the equivalent
molecular weight multiplied by the summation of the
weight fractions. The equivalent molecular weight of a
paraffin hydrocarbon compound is its true molecular
9
2
hi 4500
5
z 4000
E
; 3500
z
x 3000
i
x
GAS-OIL RATIO, CU FT/EEiL
Fig. 21.6-Influence of gas/oil ratio and tank-oil gravity on
retrograde dewpoint pressure at 160°F.
TABLE 21.13-CORRECTION TO ADD TO ASTM
VOLUMETRIC AVERAGE BOILING POINT TO OB-
TAIN MEAN AVERAGE BOILING POINT
Slope of ASTM
Curve (OF/%)
ASTM VABP (OF)
10 to 90%
points 200 300 400
500
2.0
-13- -11.5 - 10.5
-9.5
._
2.5
-17 - 15.5 - 14
-13
3.0
-22 -20 - 18.5
-17
3.5
-27 -25 -23
-21.5
4.0
-33 - 30.5 - 28.5
-26.5
4.5
- - - 34.5
-32.5
TABLE 21.15-CORRECTION TO ADD TO
ASTM VOLUMETRIC AVERAGE BOILING
POINT TO OBTAIN CUBIC AVERAGE
BOILING POINT
Slope of ASTM
Curve
(oF/%)
ASTM VABP (OF)
10 to
906/o points 200 400
600
2.0 - 5.0 -4.0
-3.5
2.5 - 6.5 - 5.5
-4.5
3.0 -8.0 -7.0
- 5.5
3.5 - 10.0 -8.5
- 7.0
4.0 - 12.5 -10.0
- 8.5
4.5 - 15.0 -12.5
- 10.0
weight. For other than straight-chain paraffin com-
pounds (isoparaffns and olefins), the equivalent
molecular weight is defined as the molecular weight that
an n-paraffin would have if it boiled at the same
temperature as the isopamftin or olefin in question.
Values of the equivalent molecular weights for natural-
gas constituents are given in Table 21.14.
The equivalent molecular weight of the C 7 + fraction
is determined by calculating the Watson characterization
factor, Kw ,
and using Fig. 21.7. Use of the
characterization factor permits some account to be taken
of the paraffinicity of the heavy-end material.
Kw=
.
3)
where Tc is the cubic average boiling point, “R. The
cubic average boiling point (Fc) is obtained by adding
the corrections in Table 21.15 to the ASTM TV, “F.
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-13
SLOPE OF ASTM DISTILLATION CURVE
lo%-90%, OF/%
TEMPERATURE.“F
Fig. 21.7-Equivalent molecular weight of C, + fraction.
Organick and Golding dewpoint lpressure
correlation.
Fig. 21.10-Saturation pressure vs. temperature at W, =80.
Parameter T,
POOC
TEMPERATURE.‘F
Fig. 21.8-Saturation pressure vs. temperature at W = 100.
Parameter Ta.
TEMPERATURE, “F
Fig. 21.9-Saturation pressure vs. temperature at W, = 90.
Parameter Ta
TEMPERATURE, “ F
Fig. 21 .ll-Saturation pressure vs. temperature at W, = 70.
Parameter T,.
Fig. 21
v “““”
3
E 5000-
a
\
6 4000-
-
;: 3000-
2
2 2000-
TEMPERATURE,“F
.12-Saturation pressure vs. temperature
Parameter Ts.
at W, =60.
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21-14
PETROLEUM ENGINEERING HANDBOOK
8000
7000
g 6000
4
g 5000
a
5 4000
F
i
3 3000
&
m 2000
0 100 200 300
TEMPERATURE.‘F
TEMPERATURE.‘F
Fig. 21.13-Saturation pressure vs. temperature at W, = 55.
Fig. 21.16-Saturation pressure vs. temperature
Parameter T
Parameter
T
TEMPERATURE.“F
Fig. 21.14-Saturation pressure vs. temperature at W = 50
Fig. 21.17-Saturation pressure vs. temperature at W =35.
Parameter T.
Parameter T.
TEMPERATURE.“F
I I
O-50 0 100
200
TEMPERATURE,“F
C
Fig. 21.15-Saturation pressure vs. temperature at W, = 45.
Parameter i;,
Fig. 21.18-Saturation pIessure vs. temperature at W, =X.5.
Parameter T.
at W =40.
L I
O-50 0
I I I” I I I
100 200 300
TEMPERATURE, OF
10
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-15
TEMPERATURE, OF TEMPERATURE, “ F
Fig. 21.19-Saturation pressure vs. temperature at W, =30.
Parameter T,.
Fig. 21.20-Saturation pressure vs. temperature at W, = 27.5.
Parameter 1,.
Example Problem 1. The dewpoint pressure at 200°F
for a well effluent having the composition shown in
Table 21.16 is predicted as follows.
1. Calculating first the properties of the separator liq-
uid CT+, we have
TV=
232+260+313+383+497
=337”F
5
and
497 -232
lo-90 slope=
=3.31.
80
From Table 21.13, MABP is 337-22.5=315”F or
775”R. From Table 21.15, CABP is 337-8.3=329”F
or 789”R, giving
3vTiG
Kw=
= 12.3.
0.7535
From Fig. 21.7 the W, for the CT + material from the
separator liquid is estimated to be 142.
Properties of the C 7 + material from the separator gas
are assumed to be equal to those of n-octane (i.e.,
Tg=718’R, W, = 114).
2. Calculating values of TB and W, for the well ef-
fluent, we obtain the results shown in Table 2 I. 17.
3. Having calculated Ts and I@, for the well effluent,
we can now determine the desired dewpoint pressure at
200°F by interpolation between Figs. 21.14 and 21.15.
At
TB
240”F, the dewpoint pressure is
w, =50 w, =45
nw
2 4000
9
g 3000
6
c 2000
2
2 1000
::
0 130 200
300
TEMPERATURE,OF
Fig. 21.21-Saturation pressure vs. temperature at W, =25.
Parameter Ts
Accuracy of Organick-Golding Correlation. About
50 of the 2 14 points that form the basis for the correla-
tion were in error less than 5 and 82 were in error
less than 10 . Standard deviation of all points is about
7.0 .
Total Formation Volume Correlations
The total formation volume factor (FVF) defines the
total volume of a system regardless of the number of
phases present. Vink
et l.
3 have shown that it is possi-
ble to have more than two hydrocarbon phases in
equilibrium when the system contains an excessively
large amount of one component. Naturally occurring
systems usually exist in either one or two phases. For
this reason, the term “two-phase formation volume” has
become synonymous with total formation volume.
The relationship of specific volume and density to the
total formation volume is the same as indicated in the
preceding section for the oil-formation volume.
4,850 4,ooO ’
Total Formation Volume Factors
and the calculated dew point (at
W, =49)
s 4,680 psia.
of Gas-Condensate Systems
It will be noticed that at 4,680 psia and 200°F the
Total formation volume factors, specific volumes, and
material is about 200°F and 900 psi above the critical densities of gas-condensate systems may be calculated
temperature and pressure of the system. (From Figs. by use of the ideal gas-law equation with the proper com-
21.14 and 2 1.15, the locus of critical states line gives pressibility factor applied provided that the liquid phase
Tc=O”F and pc=3,800 sia.)
present does not amount to an appreciable fraction of the
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21-16 PETROLEUM ENGINEERING HANDBOOK
TABLE 21.16-WELL EFFLUENT COMPOSITION
Separator
Component Gas
co*
0.0060
N2
0.0217
c:
0.8986
0.0461.0131
i-C,
0.0043
n-C
4 0.0043
i-C 5
0.0019
n-C 5
0.0017
C6
0.0019
c,+
l
0.0004
c,+ l
-
1 oooo
Mole Fraction
Separator
Liquid
Effluent”
-
-
0.0988
0.0350
0. 0381
0.0201
0.0382
0.0495
0.0313
0.1284
-
0.5606
1 oOOo
Properties of C, +
*separator gas C, + mOfec”lar we,gtlt= 114
“Separator liquid C, +
Molecular weight = 139
Density= 0.7535 g/cc=56.3°API
ASTM distillation
BP (%)
21WF
10 232
20
245
0.0056
0.0204
0.8498
0.0454
0.0146
0.0053
0.0064
0.0048
0.0035
0.0096
0.0004
0.0342
Example Problem 2. The specific volume of a gas-
condensate system at reservoir conditions given the
system molal analysis shown in Table 21.18 is calculated
as follows, assuming 1 pound mole of system.
460 + 199
Tpr =
370.7
=1.78,
2,500
-=3.75,
Ppr= 666.0
1 oooo
z=O.885 (from Fig. 20.2)
30 260
40 269
50 313
60 349
70 363
60 416
90 497
95
Endpoint
tEffluen1 comp osition calculated on the basis of separator liquid/gas
ratio 3.0 gal/lo3 cu H.
system volume. Usually, at reservoir pressures and
temperatures and for systems whose composition can be
expressed as having a surface GOR greater than 10,000
cu ft/bbl, the presence of 10 ~01 liquid phase will not
cause errors greater than 2 or 3 when the two-phase
mixture density is calculated as though the mixture ex-
isted in only a single phase. This comes about because
the partial volumes of components in the liquid phase are
substantially the same as the partial volumes of the same
components in the vapor phase.
Calculations from Composition of the Condensate
System. As outlined previously, the formation volume
(total or single phase) can be calculated from the relation
Mm vroB=-
L M,v,,
.,,.,..................~ . . .
where
Example Problem 3. The total formation volume of a
gas-condensate system at reservoir conditions given the
parameters in Table 21.19 is calculated as follows,
assuming 1 bbl of stock-tank condensate.
M, = molecular weight of reservoir system,
“RJ
= specific volume of reservoir system,
M,, = molecular weight of stock-tank oil,
VSI
= specific volume of stock-tank oil, and
L = moles of stock-tank oil per 1 mole of
3,700x0.65+170x1.20
Yg’
=0.675
reservoir system.
3,700+170
L can be calculated by use of equilibrium ratios and
and
1 bbl condensate per million cubic feet is
the methods outlined in Chap. 23.
To use the pseudoreduced-temperatuatureipseudoreduce-
d-pressure/compressibility chart in the calculation of
vrO, it is necessary to determine suitable pseudocritical
temperature and pressure values for the heptanes and
325
3.70+0.17
=84,
where yp is the gravity of total
surface
gas.
heavier components. These values can be obtained by
the chart shown in Fig. 21.22. The following example il-
lustrates the calculation of M, and v, .
and at 2,500 psia and 199°F
vro zRT 0.885 0.73~659
-
MP
19.39x2,500
=O. 129,
where
Tpr
s the pseudoreduced temperature,
ppr
he
pseudoreduced pressure, z the compressibility factor,
and v,
the specific volume (cu ftilbm) at reservoir
conditions.
In the above solution, two phases ale present at 2,500
psia, as the dewpoint pressure calculated by the method
of Organick and Golding is 2,690 psia at 199°F. Pro-
bably no correlation will indicate directly the amount of
liquid present at pressures less than the dewpoint
pressure, although it can be calculated by use of suitable
equilibrium-ratio and density data.
Calculations from GOR and Produced Fluid Proper-
ties. A second method of calculating specific volume or
formation volume on the basis of the gas-law equation
was developed by Standing. I4 This method uses a cor-
relation (Fig. 21.23) to obtain the gravity of the well ef-
fluent (or reservoir system) from the condensate liq-
uid/gas ratio, gas gravity, and the stock-tank-oil gravity
of the surface products. The effluent gravity is then used
to obtain values of pseudocritical temperatures and
pressures and, by means of these, to evaluate com-
pressibility factors for the entire effluent. The conden-
sate curve of Fig. 2 1.24 should be used when employing
this method.
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-17
TABLE 21 .17-CALCULATED VALUES OF 7, and W,
Fig.
Component
co2
F2
c:
C3
i-C 4
n-C,
i-C 5
n-C,
c6
C, + separator gas
C, + separator liquid
Fraction
0.0056
0.0204
0.8498
0.0454
0.0146
0.0053
0.0084
0.0048
0.0035
0.0096
0.0004
0.0342
Boiling
Point
(W
350
139
201
332
416
471
491
542
557
600
718
1 oooo
Fraction
Times Boiling
Point
(W
2.0
2.8
170.8
15.1
6.1
2.5
3.1
2.6
1.9
5.8
0.3
26.9
7s = 239.9
Fraction
0.0107
0.0244
0.5831
0.0586
0.0274
0.0133
0.0158
0.0150
0.0107
0.0356
0.0019
0.2035
1.0009
Weight Fraction
Times
Equivalent Equivalent
Molecular Molecular
Weight Weight
44 0.47
28 0.68
16.0 9.33
30.1 1.76
44.1 1.21
54.5 0.72
58.1 0.92
69.0 1.03
72.2 0.77
85 3.03
114 0.22
142 28.90
w, = 49.04
TABLE 21.18-CALCULATION OF SPECIFIC VOLUME OF GAS-CONDENSATE SYSTEM’
Critical
Critical
Temperature of Pressure of
Mole Molecular
Weight, ybf Components, 7, yT,
Components, pc
Component Fraction, y Weight, M
Ubm)
vu OR
wia)
YPC
co2
N2
Cl
c
C,
i-Cd
n-C‘,
i-C 5
n-C,
C6
c,+
0.0059 44.0
0.26 548 3.2 1,072 6.3
0.0218 28.0
0.61
227 4.9 492 10.7
0.8860 16.0 14.18
344 304.8 673 596.3
0.0460 30.1
1.39 550
25.3
709 32.8
0.0134 44.1
0.59 666 8.9 618 8.3
0.0045
58.1
0.26 733 3.3 530
2.4
0.0048
58.1
0.28 766 3.7 551 2.6
0.0026
72.1
0.19 830 2.2 482 1.3
0.0021 72.1 0.15 847 1.8 485 1 o
0.0037
86.2
0.32 915 3.4 434 1.6
0.0084 138 1.16
1,090’.
9.2 343” 2.9
Reservoir iemperature = 19&F
Molecular weight of C, b = 138.
Specific gravity of C, f = D 7535.
‘*Pseudocrttical values from Fig 21.22
ri ’
Id0 120 140 160 180 200 220 240
F
MOLECULAR WEIGHT
1
d BOOM.&+--+ SPkIFIC:GRAVliY 60&O -j
hw’ ’ ’ ’ ’ ’ ’ J
1 lo3 120 140 I60 180 hxl 220 240
iz
MOLECULAR WEIGHT
k
19.39
21 .Z?-Pseudocritical temperatures and pressures
heptanes and heavier.
for
370.7 666.0
1.5
060
GAS GR
1.4
0.70
GAS GR.
CFB
20 40 60 El0 ICC
Sbl Condensate per IO’ C” ft
Fig. 21.23-Effect of condensate volume on the ratio of
surface-gas gravity to well-fluid gravity.
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21-18 PETROLEUM ENGINEERING HANDBOOK
TABLE 21 .l g--DATA FOR CALCULATING TOTAL
FORMATION VOLUME OF A GAS-CONDENSATE
SYSTEM’
Reservoir pressure, psia 3,000
Reservoir temperature, OF 250
Stock-tank-condensate production, B/D 325
Stock-tank condensate gravity, OAPl
45
Tank vapor rate, IO3 cu ft/D 170
Tank vapor gravity (air = 1) 1.20
Trap gas rate, lo3 cu ft/D
3,700
Trap gas gravity, (air = 1 O) 0.65
‘0as1s 1 bbl of stock-tank condensate
TABLE 21.20-DATA FOR CORRELATION FOR
OBTAINING TOTAL FORMATION VOLUME FACTORS OF
DISSOLVED GAS AND GAS-CONDENSATE SYSTEMS
SHOWN IN FIG. 21.25
Pressure, psia 400 to 5,000
GOR, cu ft/bbl
75 to 37,000
Temperature, OF
100 to 258
Gas gravity
0.59 to 0.95
Tank-oil gravity, OAPI
16.5 to 63.8
From Fig. 21.23, at 45”API
~&~~=1.367
and
yl,,=1.367x0.675=0.923,
where
Ylw
= well fluid gravity,
ysr = trap gas gravity,
and
Ylwr
= well fluid reservoir gravity.
From Fig. 21.24,
Tpc 432
and
ppc 647.
At reservoir conditions of 3,000 psia and 250”F,
460+250
Tpr =
432
=1.64,
3,000
PPr
=------4.64,
647
and from Fig. 20.2
z=O.845.
By using 350 lbm/bbl for water, the weight of stock-
tank condensate per barrel is
350x 141.5
=281.
131.5+“API
TABLE 21.21-DATA FOR CALCULATING TOTAL
FORMATION VOLUME OF THE GAS-CONDENSATE
SYSTEM DESCRIBED IN EXAMPLE PROBLEM 4
Reservoir pressure, psia
3,000
Reservoir temperature, OF
250
GOR (condensate total), cu ft/bbl
11,900
Gas gravity (total)
0.675
Tank-oi l gravity, OAPI 45
TABLE 21.22-DATA USED TO CALCULATE TOTAL
FORMATION VOLUME FACTOR IN EXAMPLE
PROBLEM 5
Reservoir pressure, psia
Reservoir temperature, OF
GOR, cu ftlbbl
Separator
Tank
Total
Gas gravity
Tank-oil gravity, OAPI
1,329
145
566
37
603
0.674
36.4
From Fig. 21.23 the molecular weight of stock-tank
condensate, M, , is 140, moles of stock-tank condensate
per barrel is 281/140=2.00, moles of surface gas per
barrel of stock-tank condensate is l/325 x (3,870x 103)
x l/379=31.4, and total moles per barrel of stock-tank
condensate is 2.00+31.4=33.4.
From gas law,
n*T 33.4~0.845~0.73~710
y=-=
=71.7
P
3,000
and
71.7
V=-=
5.615
12.8,
where the first value of V s in cubic feet and the second
in barrels, giving a formation volume B, of 12.8 bbllbbl
of stock-tank condensate.
Total Formation Volume Factors
of Dissolved Gas Systems
A suitable correlation for obtaining total formation
volume factors of both dissolved gas and gas-condensate
systems was developed by Standing. t5 This correlation
is shown in Fig. 21.25, and the graphical chart for
simplified use of the correlation is given by Fig. 2 1.26.
The correlation contains 387 experimental points, 92
of which are within 5 of the correlation. Range of the
data comprising the correlation is given in Table 2 1.20.
Example Problem 4. The total formation volume of the
gas-condensate system described in Example Problem 3
is calculated as follows, given the data in Table 2 1.2 1.
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CRUDE-OIL & CONDENSATE PROPERTIES & CORRELATIONS
21-19
675
a
4 650
aw
2 625
i 600
2
u 575
t
5
g 550
3
; 525
4
a 500
F. 475
E
: 450
2
f 425
:
-
2
400
z 375
8
2 350
I
a 325
I I I I I I I
I
3oo
~ ~ j / 1 / 1 I I
060
080 100 120 140 160 160
Fig. 21.24-Pseudocritical properties of gases and condensate
well fluids.
Fig. 21.25-Formation volume of gas plus liquid phases from
GOR, total gas gravity, tank-oil gravity,
temperature, and pressure.
Fig. 21.26-Chart for calculating total formation volume by
Standing’s correlation.
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PETROLEUM ENGINEERING HANDBOOK
1-20
141.5
Yo=
=0.802
131.5+45
and
=11,90() (250)o’5 x~~~~~~~~.~X’~-“~ooo27x”~wo
(0.675) o.3
15.8
=11,900 -
0.877
x(O.802)‘.O
=1.72x105
where y0 is the tank-oil specific gravity.
From Fig. 21.25, B,=13+bbl/bbl oftank oil.
From Fig. 21.26, B, = 13.7 bbl/bbl of tank oil.
Example Problem
5. The total formation volume of
well production at reservoir conditions given the data in
Table 21.22 is calculated as follows.
From Fig. 21.26, B,= 1.72 bblibbl of tank oil. Ex-
perimental value calculated from PVT test results is
1.745 bbl/bbl of tank oil.
Nomenclature
B=
I, =
K=
L =
L =
M=
Mm =
Mst =
n=
PC =
Ppr =
R=
tsu =
T=
T =
Tpr =
Ta =
TB =
formation volume, m3 (bbl)
correlation index
characterization factor
moles of stock-tank condensate per barrel
moles of stock-tank oil per 1 mole of reser-
voir system, kmol/m3 (lbm moligal)
molecular weight
molecular weight of reservoir system
molecular weight of stock-tank oil
total moles
critical pressure, psia (lbflsq in.)
pseudoreduced pressure
universal gas constant
Universal Saybolt viscosity, seconds
temperature, “F
critical temperature, “C (“F)
pseudoreduced temperature
atmospheric boiling point, K (“R)
molal average boiling point, K (“R)
Tc =
cubic average boiling point, K (“R)
Tm =
mean average boiling point, K (“R)
Tm =
mean average boiling point, K (“R)
TV =
volumetric average boiling point, “F
vro =
specific volume of reservoir system
vst
=
specific volume of stock-tank oil
w =
modified weight average equivalent
Y=
molecular weight
mole fraction
z = compressibility factor
Ye
= gas specific gravity
ygt = trap
gas
gravity
Ylw
= well fluid gravity
Y wr
= well fluid reservoir gravity
Yo
= tank-oil specific gravity
p = viscosity, Pa. s (cp)
References
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
ASTM Standards on Petr oleum Products and Lubricants, Part 24,
ASTM, Philadelphia (1975) 796.
Watson, K.M., Nelson, E.F., and Murphy, G.B.: “Charactetiza-
tion of Petroleum Factions,”
I nd. and Eng. Chem. Dec. 1935)
1460-64.
Technical Dat a Book-P etr oleum Refini ng, API, Washington,
D.C. (1970) 2-11.
Nelson, W.L.: Petroleum Refinery Engineeri ng, fourth edition,
McGraw-Hill Book Co. Inc., New York City (19X3), 910-37.
“A
Guide to
World Export Crudes,” Oil and Gas J, 1976).
Ferrem, E.P. and Nichols, D.T.: “Analyses of 169
Crude Oils
fmm 122 Foreign Oil Fields,” U.S. Dept. of the Interior, Bureau
of Mines, Bartlesville, OK (1972).
Coleman, H.J. et a[.: “Analyses of 800 Crude Oils from United
States Oil Fields,” U.S. DOE, Bartlesville, OK (1978).
Woodward, P.J.: Crude Oil Analysis Data Bank, Bartlesville
Energy Technology Center, U.S. DOE, Bartlesville, OK (Oct.
1980) 1-29.
Lacey, W.N., Sage, B.H., and Kircher, C.E. Jr.: “Phase
Equilibrja in Hydrocarbon Systems III, Solubility of a Dry Natural
Gas in Crude Oil,” Ind. and Eng. Chem. (June 1934) 652-54.
Sage, B.H. andOlds, R.H.: “VolumetricBehaviorofOiland Gas
from Several San Joaquin Valley Fields,” Trans., AIME (1947)
170, 156-62.
Organick, E.I.
and
Golding, B.H.: “Prediction of Saturation
Pressures
for
Condensate-gas and
Volatile-oil Mixtures,” Trans.,
AIME (1952), 195, 135-48.
Smith, R.L. and Watson, K.M.: “Boiling Points and Critical
Pmperties of Hydrocarbon Mixtures.” Ind. and Enn. Chem.
(19j7) 1408.
Vink, D.J. er al.: “Multiple-phase Hydrocarbon Systems,” Oil
and Gas J. Nov . 1940) 34-38.
14. Standing, M.B.: Volum etr ic and Phase Behavi or of O il Field
Hy drocarbon Systems,Reinhold Publishing Corp., New York Ci-
ty (1952).
15. Standing, M.B.: “A Pressure-Volume-Temperature Correlation
for Mixtures of California Oils and Gases,” Dri l l . and Prod.
Prac., API (1947), 275.