oil and condensate

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 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 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 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 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 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, 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 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 31 46 65 46 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 for catalflic cracking. The Cycle stcck IrOm catalytic cracking is thermally cracked along wtth the asphalt or vis- breaker chargestock.

“Average gravity from instantaneous curve 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 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 in intermediate paraffin naphthene

intermediate paraffin intermediate intermediate intermediate naphthene naphthene intermediate naphthene paraffin naphthene naphthene

‘USBM, Repon 3279 (Sept. 1935). “Universal Oil Products Co.. Chicago

40+ 40+

33 to 40 33 to 40 33 to 40

33- 33- 33-

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 12.0 to 12.2+ 11.4 12.1 to 11.4 to 12.1 11.4 12.1 to 11.4-

11.5- 11.4 to 12.1 11.5- 12.2+ 11.4- 11.4-

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 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 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,

3% K=- 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 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

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 characterization 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 Technical Data Book3 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.


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 lrom factors of raw and dewaxed lube 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” +

PERCENTAGE DISTILLED 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

1100

1000

900

800

700

600

500

400

300

200

100

9.0

8.0

7-o

6.0

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.


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 correction factor for other bases of oils.

1,.,!,,,,,,., K =CHARACTEklZATION FACTOR = 3MOLAL AVG. BOILING POINT,“R

- / SPEClF(C G.,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.


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


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

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

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

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, 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.


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 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 1 OO°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


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 1 OO°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

30 1.46481 30 1.47017 33 1.47736 35 38

141.2 40 14

145.6 148.4 i: ii 96 76

179 98

7.1 1.4 0.67 0.235

5oto 100

loot0 200 >200

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-

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” published 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


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 of (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 correlation 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.

Organick and Golding’s Correlation

This correlation relates saturation pressure of a system directly to its chemical composition by geans of two generalized composition characteristics TB, the molal average boiling point, and W,, a modified weight average equivalent molecular weight. The saturation pressure may be either bubble-point pressure, dewpoint pressure, or the very special case of critical pressure. The 15 working charts (Figs. 21.7 through 21.21) cover

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. The molal average boiling point of the system is defined as

TB=CyxTa, . . . . . . . . . . . . . . . . . . . . . . . . . . ...(l)

where y is the mole fraction and T, the atmospheric boiling point.

Boiling points of the pure compounds (methane, ethane, nitrogen, carbon dioxide, etc.) are listed in Chap. 20. The boiling point of the CT + fraction is taken as the Smith and Watson I2 mean average boiling point (MABP). The MABP can be calculated from the ASTM distillation curve, the procedure being first to calculate the ASTM volumetric average boiling point (VABP, “F) and then to apply a correction factor to obtain the


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 1 60°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 compounds (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.


SLOPE OF ASTM DISTILLATION CURVE lo%-90%, OF/% TEMPERATURE.“F

Fig. 21.7-Equivalent molecular weight of C, + fraction. Organick and Golding dewpointlpressure 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.


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


TEMPERATURE, OF

Fig. 21.19-Saturation pressure vs. temperature at W, =30. Parameter T,.

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 liquid 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 effluent, 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

4,850 4,ooO ’

and the calculated dew point (at W, =49) is 4,680 psia. It will be noticed that at 4,680 psia and 200°F the

material is about 200°F and 900 psi above the critical temperature and pressure of the system. (From Figs. 21.14 and 2 1.15, the locus of critical states line gives Tc=O”F and pc=3,800 psia.)

TEMPERATURE, “F

Fig. 21.20-Saturation pressure vs. temperature at W, = 27.5. Parameter 1,.

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 correlation 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 al. I3 have shown that it is possible 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.

Total Formation Volume Factors of Gas-Condensate Systems

Total formation volume factors, specific volumes, and densities of gas-condensate systems may be calculated by use of the ideal gas-law equation with the proper compressibility factor applied provided that the liquid phase present does not amount to an appreciable fraction of the


TABLE 21.16-WELL EFFLUENT COMPOSITION

Separator Component Gas

co* 0.0060 N2 0.0217

c: 3

0.8986

0.0461 0.0131 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

1 .oooo

30 260 40 269 50 313 60 349 70 363 60 416 90 497 95

Endpoint tEffluen1 composition 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 vro B=- L M,,v,, .,,.,..................~ . . .

where 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

reservoir system.

L can be calculated by use of equilibrium ratios and 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

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

z=O.885 (from Fig. 20.2)

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.

3,700x0.65+170x1.20 Yg’ =0.675

3,700+170

and 1 bbl condensate per million cubic feet is

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 x 10.73~659 -

MP 19.39x2,500 =O. 129,

where Tpr is the pseudoreduced temperature, ppr the 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 correlation (Fig. 21.23) to obtain the gravity of the well effluent (or reservoir system) from the condensate liquid/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 compressibility factors for the entire effluent. The condensate curve of Fig. 2 1.24 should be used when employing this method.


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.


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-oil 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~ 10.73~710 y=-= =71.7

P 3,000

and

71.7 V=-=

5.615 12.8,

where the first value of V is 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.


675

a 4 650

aw 2 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.

PETROLEUM ENGINEERING HANDBOOK 21-20

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 lwr = 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 Petroleum Products and Lubricants, Part 24, ASTM, Philadelphia (1975) 796. Watson, K.M., Nelson, E.F., and Murphy, G.B.: “Charactetiza- tion of Petroleum Factions,” Ind. and Eng. Chem. (Dec. 1935) 1460-64. Technical Data Book-Petroleum Refining, API, Washington, D.C. (1970) 2-11. Nelson, W.L.: Petroleum Refinery Engineering, 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.: Volumetric and Phase Behavior of Oil Field Hydrocarbon 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,” Drill. and Prod. Prac., API (1947), 275.

oil and condensate

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