Crude Oil Properties and Condensate Properties and Correlati

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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



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



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.



21-4


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.





21-6


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.




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



21-8


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.




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


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


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


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



21-10


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




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



21-12


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.




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.



21-14


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. 21.16-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


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




21-15

TEMPERATURE, OF TEMPERATURE, “ F


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


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



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.




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.



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.




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.




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.

Documents

Crude Oil Properties and Condensate Properties and Correlati