Petroleum Engineers Handbook, Part 3

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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 carbon 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 compounds in it, it has been impossible so far to develop exact 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 present 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 products. Table 2 1.2 gives the chemical analysis of several fractions of four crude oils. The crude-oil evaluation consists primarily of a fractional distillation of the oil followed by physicalproperty 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 evaluation curves, Table 2 1.3 shows product yields and properties when a refinery is operated for maximum gasoline yield, and Table 2 1.4 shows product yields and properties when the objective is to produce lubricating oils and diesel fuel. Since the early 1970’s, much research has-been performed on the use of the gas chromatograph to generate simulated distillations. This has the advantage of producing 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 column 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, intermediate, 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

TABLE Pl.l-ULTIMATE Specific Gravity -r

Petroleum

0.862 0.897 0.912

Pennsylvania pipeline Mecook, WV Humbolt, KS Healdton, OK Coalinga, CA Beaumont, TX Mexico Baku, USSR Colombia, South America

CHEMICAL ANALYSES

Temperature PC) 15 0

0.951 0.91 0.97 0.897 0.948

C 85.5 83.6 85.6 85.0 86.4 85.7 83.0 66.5 65.62

15 15 20

HANDBOOK

OF PETROLEUM

H 14.2 12.9 12.4 12.9 11.7 11.0 11 .o 12.0 11.91

Component WI N 0

--

-

Base

S

paraffin paraffin mixed mixed

3.6

1.14 2.61 1.7*

0.37 0.76 0.60 0.70 4.30

l

naphthene

naphthene naphthene

1.5 0.54

‘Combined mtrogen and oxygen.

TABLE 21.2-CHEMICAL

Fraction (“0 140 to 203 to 252 to 302 to 392 to 482 to

203 252 302 392 482 572

Grozny (“High Paraffin”) 45.3% at 572OF Aromatic

ANALYSES OF PETROLEUM, %

Grozny (“ParaffinFree Upper Level”), 40.9% at 572OF

Oklahoma 64% at 572OF

Naphthene

Paraffin

Aromatic

Naphthene

Paraffin

Aromatlc

Naphthene

Paraffin

25 30 35 29 23 22

72 65 56 57 59 61

4 8 13 21 26 35

31 40 52 55 63 57

65 52 35 24 11 8

5 7 12 16 17 17

21 28 33 29 31 32

73 65 55 55 52 51

3 z 14 18 17

TABLE 21.3-EVALUATION

Percent Distilled Gas loss Straight-run gasoline (untreated) Catalytic charge

Range

54.5 octane number 900°F cut

0 to 1.3 1.3 to 32 32 to 80.5

remainder

80.5 to 100

charge or asphalt

Aromatic

-A

i 11

17 25 29

Naohthene

Paraffin

31 46 64 61 45 40

65 46 25 22 30 31

WHEN OPERATING PRIMARILY FOR GASOLINE’

Basis

Material

V&breaker Crude oil

California (Huntmgton Beach), 34.2% at 57Z°F

(Davenport),

‘Topping follwed by YaWUrn flashing to produce a gas 011for catalflic cracking. breaker chargestock.

Midpoint ~16.6 56.2

Yield 1.3 30.7 48.5 19.5 100.0

Gravity (OAPI) 56” 28.8 6.4$ 32.0

Other Properties 390DF ASTM endpoint7 165OF aniline point or 47.5 diesel index 110 penetration 11.65 characterization factor

The Cycle stcck IrOm catalytic cracking is thermally cracked along wtth the asphalt or vis-

“Average gravity from instantaneouscurve of API gravity. ?At about 400aF endpoint the 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 Percent Distilled

Material

Basis

Gas loss

Light gasoline (untreated) Reforming naphtha Diesel fuel

300 EPb 445 EPb 156 aniline point

Light lube or cracking stock Lube stock (untreated) Asphalt Crude oil

remainder 100 W’s

viscosity at 2lOOF

100 penetration

Range 0 to 1.3 lo 21 .O to 38.5 to 56.5 to 74.9 to 80.9 to

Midpoint

-13 1.3 21.0 10.5 38.5 29.7 56.5 47.5 74.9 65.7 80.9 77.9 100.0

Yield 19.7 17.5 18.0 18.4 6.0 19.1 100.0

API Gravity 61.2C 41.3e 32.1 25.9 19.1

Viscosity, SU’S

STOCK0

Other Properties

63.8 octane numberd 0.16% sulfur 41 (estimated) 50 diesel Index; 0.82% sulfur 145 at 100°F 1.49% sulfur’ 100 at 210°F

100 penetration at 77OFg 32.0

CRUDE-OIL & CONDENSATE

21-3

PROPERTIES & CORRELATIONS

TABLE 21.5-BASES

OF CRUDE OILS’

API Gravity at 60°F Low-Boiling

Part paraffin baraffin paraffin intermediate intermediate intermediate naphthene naphthene naphthene

Approximate

UOP* *

Characterization Factor

High-Boiling

Key Fraction

Part

1

Key Fraction 2

LowBoiling

HighBoiling

paraffin intermediate naphthene paraffin intermediate naphthene intermediate paraffin naphthene

40+ 40+ 40+ 33 to 40 33 to 40 33 to 40 333333-

30+ 20 to 30 2030+ 20 to 30 2020 to 30 30+ 20-

12.2+ 12.2+ 12.2 + 11.5 to 12.0 11.4 to 12.1 11.4 to 12.1 11.511.511.4-

12.2+ 11.4 to 12.0 11.412.2+ 11.4 to 12.1 11.411.4 to 12.1 12.2+ 11.4-

‘USBM, Repon3279 (Sept.1935). “Universal

Oil Products Co.. Chicago

its light materials and another set for the heavy-lube fractions, 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 atmospheric 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 added. If the pour point is below 5”F, it is termed “waxfree.” would mean Thus, “paraffin-intermediate-wax-free” a crude that has paraffinic characteristics in the gasoline portion and intermediate characteristics in the lube portion 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,

K=- 3% 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 boiling point defined above, a number of other physical properties have been shown to be related to the chamcterization 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

TABLE 21.6-TYPICAL CHARACTERIZATION FACTOR VALUES

Product Pennsylvania stocks (paraffin base) Mid-Continent stocks (intermediate) Gulf Coast stocks (naphthene base) Cracked gasoline Cracking-plant combined feeds Recycle stocks Cracked residuum

Characterization Factor 12.1 11.8 11 .o 11.5 10.5 10.0 9.8

to to to to to to to

12.5 12.0 11.6 11.8 11.5 11.0 11 .O

number of worldwide crudes and products and typical hydrocarbon compounds that have the same characterization factor as the oil in question.

Physical Properties Fig. 21.2 shows the relationship of carbon-tohydrogen ratio, average molecular weight, and mean average boiling point as a function of API gravity and characterization factor. The API Technical DataBook3 has published a number of correlations for physical properties 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 latent heat. Certain corrections must be applied for characterization factor and for pressure.

21-4

PETROLEUM

TABLE 21.7-CHARACTERIZATION Characterization Factor

FACTORS OF A FEW HYDROCARBONS,

Hydrocarbons

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

11.45 11.4 11.3to 11.6 11.3

PETROLEUMS,

Typical Crude Oils

HANDBOOK

AND TYPICAL STOCKS

Miscellaneous Products

94.5 API adsorption gasoline Four Venezuelan paraffin waxes paraffin wax*: MC. 82.2 API natural gasoline CA 81.9 API natural gasoline Cotton Valley (LA) lubes Pennsylvania-Rodessa Big Lake (TX) Lance Creek (WY) Mid-Continent (MC.) Oklahoma City (OK)

debutanized E. TX natural gasoline San Joaquin (Venezuela) wax distillate Panhandle (TX) lubes Six Venezuelan wax distillates

(LA)

paraffin-base gasolines

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)

butylcyclohexane octyl or diamyl benzene

ethylcyclohexane and 9-hexyl-l l-methylheptadiene methylcyctohexane

Elk Basin, heavy (WY) Kettleman Hills (CA) Smackover (AR)

cyclobutane and 2,6,10,14tetramethyl

Lagunillas (Venezuela) Gulf Coast light distillates

hexadiene

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

‘12.66 (range 12.1 to 13.65) calculated lrom factors of raw and dewaxed lube stocks

‘\

+

ENGINEERING

/

*.-

,

IO

20

(YIELD1

,

1

I

I

30 40 50 60 i-0 PERCENTAGEDISTILLED

I

80

I

,

90

100”

I

I

Ftg. 21 .l-Evaluation curves of a 32.0°API intermediate-base crude oil of characterization factor 11.65.

CRUDE-OIL 8 CONDENSATE

PROPERTIES & CORRELATIONS

21-5

9.0

8.0

7-o

6.0

1100

1000

900

800

700

600

500

400

300

200

100 IO

20

30

40

50

Fig. 21.2-Petroleum properties as a function of API gravity and characterization factor. Note: the parameters in the curves refer to the characterization factor.

21-6

PETROLEUM ENGINEERING

I

i

I

0

I

I

I

I

200

I

I

I

I

I

I

I

I

I

I

400 600 TEMPERATURE,“F

I

I

III

HANDBOOK

I

000

Fig. 21.3-Specific heats of Mid-Continent liquid oils with a correction factor for other bases of oils.

m

7 / L o-

o-

o-

1,.,!,,,,,,.,

o-

K=CHARACTEklZATIONFACTOR = 3MOLAL AVG. BOILINGPOINT,“R / SPEClF(CG.,ilTYf~

9 3-

I I 000 , OF

34 0

Fig. 21.4-Heat

I 900

I 1,000

/ 1,100

content of petroleum fractions including the effect of pressure.

I 1,200

CRUDE-OIL

& CONDENSATE

PROPERTIES

21-7

& CORRELATIONS

TABLE 21.8-TRUE-BOILING-POINT

CRUDE OIL ANALYSES Location

Atlanta, AR (limestone)

Kern River, CA

Santa Maria, CA

Coalinga (East), CA

Coalinga, CA

20.5 2.30 270 413139

44.5 0.48c 35

10.7 1.23 6,000 +

15.4 4.63 368 812154

20.7 0.51 178

31.1 0.31 40

11.62 11.48 11.47 11.55 11.53 I 0

11.82 12.05 12.08 12.25 12.05 IP 1.5

6.0 73.2a a9.0a 11 .o 66.0b 14.4 good b

45.3d

2.P

24.1 41.9 good

56.3d 57.4

6.1 d 29.5b

9.5 38.0 16.0b 0.29b

15.0d 46.0 27.0b 0.06b excellent

43.0b Ob 0.82 b

Smackover, AR 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 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

N 0

11.90 11.42 11.29 11.11 11.48 IN 0

25.2d

0

7.0

1.2d

21 .6d 72.ob

39.2d

1.2d

13.2 59.8e 70.30 17.0

9.6d 67.0 b

31 .6d 66.7b

15.6d good b

35.6d excellent b

25.0 43.0 good

29.3d 36.9

46.2d 46.0d good

2.7d 32.5d 13.0b 0.38b

8.5 34.5 1.8d

16.0d 34.0d 14.5b o.ub

Il.Od 37.0 17.0b 0.06b

35.0d 76.0d high 0.15b

19.7d mob - 30.0b

23.8 33.0 - 3.0 2.56

38.4d 33.0b -25.ob 0.35b

28.0d 48.5” 20.0b 0.W’

48.2 71.4b 25.7

51.4d 64.5 b 35.5

41.8d 7.5.6b 20.0 good

39.8 75.6d 22.8

59.46 22.3 excellent

45.6d 70.4b 28.0 good

75.9

42.2d

27.1 9.6 54.9 23.2

93.9d 9.1

75.0

14.7 4.8 35.5 27.0

i:: 15.0 11.0

67.7d 11 .o 4.2 27.5 18.6

52.P 18.2 5.0 42.2 22.2

19.0

16.4d

16.0

13.06

17.6d

0.67b

56.0b 0.43b

28.0d excellent

21.7d good

29.2

37.0b 2.45 b 40.8 good

11.13 11.15 11.15

48.5b

113.0b 0.8b excellent 7.9d

0.8b

22.2d

1.5b 57.0d excellent

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

47.0 excellent

11.28 11.20 11.23 N 3.0

11.5 11.53 11.59 11.72 11.58 I 1.1

21-8

PETROLEUM

TABLE 21.9-ANALYSIS

Chapel Hill Palusy Zone 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 Total Liquid gravity, OAPI Llquld mol wt Liquid analysts Light gasoline Naphtha Kerosene dtstlllate Gas oil Nonviscous lube Residuum and loss

ENGINEERING

HANDBOOK

OF CONDENSATE LIQUID AND GAS FROM SELECTED TEXAS ZONES Carthage Upper Pettite Zone

Carthage Lower Pettile Zone

Old Ocean Chenault Zone

Old Ocean Larson Zone

Seellgson 21 D Zone

Seeligson 21 A Zone

Saxet

67 20.19

752 85 20.76

702 85 20.51

810 80 20 64

410 85 20.63

1087 88 21.34

645 82 25.03

607 70 19.62

88.74 20.18

16.23 18.25

29.28 18.25

29.33 18.70

28.71 18.17

29.88 18.42

24.48 18.69

41.33 18.89

0.794 1.375 76.432 7.923 4.301 1.198 1.862 0.937 0.781 1.415 2.992 100.00 71.8 68.64

0.695 1.480 89.045 4.691 1.393 0.401 0.394 0.283 0.191 0.379 1.098 100.00 61.0 91.51

0.646 1.967 88.799 3.363 1.536 0.335 0.583 0.302 0.254 0.574 1.641 100.00 64.8 81.55

0.448 0.370 87.584 5.312 2.302 0.584 0.630 0.416 0.207 0.505 1.642 100.00 54 0 85.93

0.468 0.414 90.162 4.067 1.616 0.464 0.390 0.274 0.123 0.418 1.604 100 00 47.6 110.07

0.130 0 075 89.498 4 555 1 909 0 465 0 493 0.286 0209 0 385 2015 100.00 52.7 94.49

0.200 0.253 88.731 5.224 1.795 0.488 0.452 0.172 0.241 0.414 2.032 100.00 52.1 103.22

0.299 0.281 86.733 4.816 2.873 0.836 0.788 0.583 0.256 0.633 2.102 10000 60.0 68.73

Vol % ---__ 55.1 37.2 21.1

5.6

632-

OAPI Vol %

OAPI

Vol %

“API

Vol %

82.9 60.5 50.8

74.8 59 2 48.1

40.7 47.0 79

76.6 59.3 47.6

21.2 55.3 15.0 3.8

29.1 48.4 18.2

4.3

4.4

4.7

‘=APl Vol % --71.2 14.7 52.9 36.9 42.6 17.4 37.8 21.3 74 2.3

“API

Vol %

70.9 52.2 42.1 36.6 29.8

22.6 47.7 15.9 7.3 6.5

OAPI Vol %

‘API

Vol %

OAPI

70.1 53.4 43.8 37.4

68.4 53.1 43.0 37.0

35.7 47.6 10.0 2.4

73.6 55.9 44.9 38.2

20.7 49.5 16.1 7.2 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 common 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 5 =0.219ts” Yo

--,

149.7 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

Fig. 21.5-Approximate relation between viscosity, ture, and characterization factor.

tempera-

Crude-Oil Analyses

A number of true-boiling-point crude-oil analyses are included in Table 21.8. In addition to the gravity, viscosity, 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 according to state, and within each group according to gravity.

CRUDE-OIL

& CONDENSATE

PROPERTIES

& CORRELATIONS

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 products 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 distillation 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 fractions 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 example, YEAR, APIG, LOC, GEOL and SULF, allow a search on year analyzed, API gravity, location by state and country, 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.

21-9

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%

36.3 1 .o 0.21 +20 42.40 5.1 14.5 1.0

Gasoline Range, OF Yield, VOWI Gravity, OAPI Sulfur, wt% Research octane number, clear Research octane number, - 3 mL tetraethyl lead per gallon

60

to 200 10.7 77.2 0.003 74.4 90.0

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 Yield, ~01% Gravity, OAPI Viscosity, SUS at lOOoF Freezing point, OF Aromatics, VOW (0 + A) Sulfur, wt% Aniline point, OF Smoke point, mm

400 to 500 13.5 40.2 32.33 -38 13.1 p,, . the oil density is calculated from p. =poh exp[c,(p--ph)], where PO poh p pb

..

.

.(2)

= = = =

oil density at p, T, oil density at ph, T, pressure, psia, bubblepoint pressure at T, psia, and co = oil isothermal compressibility at T, psi - ’ .

Correlations for calculating R,T, B,, c, and ~b at various conditions are presented later. In the petroleum industry, it is common to express gravity in terms of the API gravity of the oil, or: 141.5 Yo = 131,5+YAP,,

.

..

.

.

where y. is oil specific gravity, and YAPI is oil gravity, “API. Density From Ideal Solution PrinciplesComposition Known

Fig. 22.1-Pseudoliquid density methane and ethane.

of

systems

containing

The principle of ideal solutions states that the volume of the total solution is the sum of the individual component volumes. The principle applies at atmospheric pressure for fluids in which the components are closely related chemically, such as petroleum. If the composition of the fluid is known, the density at standard conditions (14.7 psia and 60°F) may be calculated from

Oil Density Determination Oil density is required at various pressures and at reservoir temperature for reservoir engineering calculations. The variation with temperature must be calculated for production system design calculations. An equation for oil density is

c &

mi -

Psc = 5 i=l

Cm I Cmilpi

)

.

.

(4)

vi

where 350y,+O.O7647,R, 5.6158, PO =

= mass of the ith component, = volume of the ith component, PI = density of the ith component at standard conditions, and C = number of components.

m; ,

I..

.

.

. . .

where PO = Yo = YK = R,y = B, = 3.50 =

oil density, lbmicu ft, oil specific gravity, gas specific gravity, solution or dissolved gas, scf/STB, oil FVF, bbl/STB, density of water at standard conditions, lbm/STB, 0.0764 = density of air at standard conditions, lbmlscf, and 5.615 = conversion factor, cu ft/bbl.

If the pressure and temperature conditions are such that all of the available gas is in solution-i.e., the pressure is above the bubblepoint at the temperature of interest-

Vi

Once the density at standard conditions is calculated, it must be corrected for compressibility and thermal expansion if the density at other conditions is required. This can be accomplished by use of charts presented by Standing. ’ When the ideal solution principle is applied to reservoir ,oils that contain large amounts of dissolved gas, it is obvious that the fluid cannot be brought to standard or stock-tank conditions and still remain in the liquid phase. This limitation is overcome by calculating a pseudoliquid density, the value of which depends on the mass or weight fractions of methane and ethane in the fluid. The pseudoliquid density correlation was presented by Standing ’ and is illustrated in Fig. 22. I,

22-3

OIL SYSTEM CORRELATIONS

10 b-

9

: G

B

E5 a

7

F

6

4I b3 mu =\

5

0-J WC0 4 IL $

3

G

2

zP

1

i? DENSITY AT 6O”F, 1 ATM, LBKU

Fig. 22.2-Density correction for compressibility of hydrocarbon liquids.

The procedure for calculating oil density at any pressure and temperature when the composition is known is as follows. 1. Calculate the mass or weight of the ethane and heavier components in the mixture. 2. Calculate the density of the propane and heavier components with Eq. 4. 3. Calculate the weight or mass percent of ethane in the ethane and heavier mixture. 4. Calculate the weight percent methane in the total mixture. 5. Determine the pseudoliquid density from Fig. 22.1. 6. Correct for compressibility with Fig. 22.2 7. Correct for thermal expansion with Fig. 22.3. Example Problem 1. Using the known composition of a reservoir fluid as given in Table 22.1, calculate the den-

TABLE 22.1-

Component Cl C* C3 C4 C5 C6 C T&l

Mole Fraction. Y, 0.4404 0.0432 0.0405 0.0284 0.0174 0.0290 0.4011 1 .oooo

‘at 60°F and 14.7 ps,a. “Arithmetic average of is.0 and normal

Mole Weight of Components, M, 16.0 30.1 44.1 58.1 72.2 86.2 297

values

‘25

30

FT

45 50 55 35 40 DENSITY AT 60°F

Fig. 22.3-Density correction for thermal hydrocarbon liquids.

60

expansion

65

of

sity at the bubblepoint pressure of 3,280 psi and temperature of 218°F. Solution.

1. Weight of ethane plus=130.69-7.046=123.46 lbm. 2. Density of propane plus equals (weight of propane plus) divided by (volume of propane plus): 130.69-7.046-1.296

=54.94 lbm/cu ft.

2.227 3. Weight percent ethane in ethane plus: 1.296(100)

= 1.05.

123.46

EXAMPLE PROBLEM 1 SOLUTION

Weight of Components mi =Y,M, (Ibm) 7.046 1.296 1.766 1.650 1.256 2.500 115.1 130.69

Liquid Density of Components,’ PI

31.66 35.77’ 39.16’* 41.43 56.6

l

Liquid Volume of Components,’ V, =m,lp, fcu ft\

0.0564 0.0461 0.0321 0.0603 2.032 2.227

PETROLEUM ENGINEERING

22-4

HANDBOOK

is 27.4”API and the quantities and gravities of the produced gas are given in Table 22.2. Solution.

1. Average gas gravity, yr. =CI?iy,~iICRj, (414)(0.640)+90(0.897)+25(1.540) r, =

=. 726 . .

414+90+25

and 141.5 I”‘= 131.5+27.4

GAS GRAVITY, AIR

q

1

=0.89.

2. Molecular weight of produced gas, M,, =y,(M,i,); M,Y=0.726(28.97)=21.03

Fig. 22.4-Apparent

Ibmimol.

liquid density of natural gases.

3. Mass of dissolved gas, m,, is given by 529 scf/STB 379,5 scf,mol (21.03 lbm/mol)=29.32

lbm/STB.

4. Weight percent methane in methane plus: 7.046(100)

4. Mass of stock-tank oil, m,,, is given by =5.39.

130.69 5. From Fig. 22.1, psr=50.8 lbm/cu ft at 60°F and 14.7 psia. 6. From Fig. 22.2, the correction for pressure is 0.89 lbmicu ft. Therefore, the density at 3,280 psia and 60°F is 50.8+0.89=51.7 lbmicu ft. 7. From Fig. 22.3, the correction for temperature is -3.57 Ibm/cu ft. Therefore, the density at 3,280 psia and 218°F is 51.7-3.57=48.1 Ibm/cu ft.

350 lbm/STB(O. 89) = 3 11.50 lbm/STB. Fig. 22.4 shows that the apparent liquid density of the dissolved gas is about 24.9 lbmicu ft at 60°F and 14.7 psia. This is used to calculate the volume of the dissolved gas. 5. Volume of dissolved gas, I’,, is given by

mR -=

29.32 lbm/STB

= 1.178 cu ft/STB.

PK 24.9 lbmicu ft 6. Volume of stock-tank

04 V,, is given by

5.615 cu ft/STB. Density From Ideal Solution PrinciplesComposition Unknown The procedure for estimating oil density outlined in the preceding section used charts for determing the apparent gas density, which required knowledge of the total fluid composition. Katz* extended the apparent density concept to apply to natural gases in general. This results in a method that can be used when solution GOR stock-tankoil gravity, and gas gravity are known. The fluid composition is not required. The correlation for the apparent density of the dissolved gas as a function of oil and gas gravity is shown in Fig. 22.4. The gravity of the produced gas is calculated as a volume-weighted average of the gas evolved at the separator and the stock tank. Application of Fig. 22.4 in estimating the oil density from limited data is illustrated in Example Problem 2. In this example, the fluid passed through two separators between the wellhead and the stock tank. Example Problem 2. Calculate the density and specific volume of the oil system at the bubblepoint conditions of pb =3,280 psia at T=218”F. The stock-tank oil gravity

7. Pseudoliquid density,

PAL

zz-m, fm,

“0 - “, - 311.50 lbm/STB+29 32 1bmiSTB - 5.615 cu ft/STB+1.178 cu ft/STB =50.17 Ibm/cu ft.

TABLE 22.2-PRODUCED CHARACTERISTICS

GAS

R (scf/STB) First-stage separator Second-stage separator Stock tank Total

414 90 25 529

y9 0.640 0.897 1.540

22-5

OIL SYSTEM CORRELATIONS

Correction of the density for compression and thermal expansion is accomplished with Figs. 22.2 and 22.3. Fig. 22.2 shows that the pressure correction to 3,280 psia is 0.90 lbmicu ft. Therefore, p3Z80,60=50.17+0.90=51.07

lbmicu ft.

Fig, 22.3 shows that the temperature 218°F is -3.63 Ibm/cu ft. Therefore,

correction

characterize the tank oils other than by the API gravity. The value for gas gravity to be used is apparently the volume-weighted average of the gas from all stages of separation. The correlation should apply to other oil systems as long as the compositional makeup of the gases and crudes is similar to those used in developing the method. The equation for estimating bubblepoint pressure is

to 0.83 x IO!‘v ,

~32~0,218=51.07-3.63=47.44

(5)

lbmicu ft where

The specific volume of the oil is defined as the reciprocal of the density. Therefore, I = -----0.021 47.44 P 0

v,, = i

Bubblepoint-Pressure

cu ft/lbm.

Correlations

Reservoir performance calculations require that the reservoir bubblepoint pressure be known. This is determined from a PVT analysis of a reservoir fluid sample or calculated by flash calculation procedures if the composition of the reservoir fluid is known. However, since this information is frequently unavailable. empirical correlations for estimating P/, from limited data were developed. These correlations may be used to estimate bubblepoint or saturation pressure as a function of reservoir temperature, stock-tank oil gravity. dissolved-gas gravity, and solution GOR at initial reservoir pressure. That is,

Y