Jones D.S.J., Pujado P.R. Handbook of Petroleum Processing

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714 CHAPTER 16

Table 16.10. Speciﬁcation for basic (single grade) lube oil grades

Max viscosity @ Max viscosity @ Min viscosity @

Grade 0

◦

F SUS 210

◦

F SUS 210

◦

F SUS

5 W 6,000 – –

10 W 12,000 – –

20 W 48,000 – –

SAE 20 – 58 45

SAE 30 – 70 58

SAE 40 – 86 70

SAE 50 – 110 85

Petroleum coke

Petroleum coke is not found in crude oil, but is the carbon compound formed from the

thermal conversion of petroleum containing resins and asphaltenes. Coke is formed

in the processes to convert the residuum fuels to the more desirable distillate products

of naphtha and lighter through to the middle distillates. There are two routes by

which this coking process proceeds. The ﬁrst and the most common is the delayed

coking route. The second is the ﬂuid coking method, and this has been made more

attractive to many reﬁners with the development of Exxon Mobil’s proprietary process

of Flexicoking. This proprietary process eliminates the coke completely by converting

it to low Btu fuel gas. By far the largest production of coke is the sponge coke from

the delayed coking process. Uncalcined sponge coke has a heating value of about

14,000 Btu/lb and is used primarily as a fuel. High sulfur sponge coke however

is popular for use in cement plants since the sulfur reacts to form sulfates. Sponge

coke is calcined to produce a coke grade suitable for anodes in the aluminum industry.

Details of the speciﬁcations for green (uncalcined) coke and calcined coke are given as

Table 16.11.

Table 16.11. Speciﬁcation for sponge coke

Parameter Green coke Calcined coke

Fixed carbon % 86–92 99.5

Moisture % 6–14 0.1

Volatile matter % 8–14 0.5

Sulfur % <2.5 <2.5

Ash % 0.25 0.4

Silicon % 0.02 0.02

Nickel % 0.02 0.03

Vanadium % 0.02 0.03

Iron % 0.01 0.02

QUALITY CONTROL OF PRODUCTS IN PETROLEUM REFINING 715

Table 16.12. A typical speciﬁcation for sulfur

Purity 99.8 wt% sulfur, on a dry basis.

Ash 500 ppm by weight maximum

Carbon 1,000 ppm by weight maximum

Color Bright Yellow

Hydrogen

sulﬁde

10 ppm by weight maximum. This is particularly

important for international transport and sales

State Shipped either liquid or solid

Sulfur

Sulfur is a byproduct of modern day reﬁneries. By the processes that make up the

modern hydrogen skimming reﬁnery a signiﬁcant portion of the sulfur contained in

the crude is removed as elemental sulfur for marketing as a product. It is true to

say that as the environmental requirements for reduced sulfur levels in products and

emissions from the reﬁnery decreases the sulfur produced as a product increases. In

most countries today over half of the required sulfur is produced from the petroleum

and gas industries. Sulfur is stored and transported from the reﬁnery as a molten

product or as solid sulfur. Almost half the world’s sulfur production is used in making

sulfuric acid and phosphate fertilizers using the sulfuric acid produced from the sulfur.

A typical speciﬁcation for sulfur is given as Table 16.12.

16.2 The description of some of the more common tests

The tests described here are usually carried out in the reﬁnery laboratory. The results

these tests are used in plant control and for the quality control of ﬁnished products.

There are many more laboratory and other tests that are carried out in the reﬁnery

company’s research and development establishment. These later tests are carried out

to improve product quality parameters or to establish design data for processes and

development work. These later tests would include mass spectrometry for crude oil

data and assay development, pilot plant tests to establish optimum operating data, and

items such as motor vehicle road tests. Those tests described brieﬂy in the following

sections are those listed earlier.

Speciﬁc gravity (D1298)

Density ASTM D 1298—Density, relative density (speciﬁc gravity), or API gravity

of crude petroleum and liquid petroleum products by hydrometer method. Fuel is

transferred to a cylindrical container and a hydrometer is carefully lowered into the

cylinder and allowed to settle. After the temperature of the sample has equilibrated,

the value on the hydrometer scale positioned at the surface of the sample and the

716 CHAPTER 16

Table 16.13. Relationship of speciﬁc gravity @ 60

◦

API, and lbs/US gal

◦

API 10 20 30 40 50 60

Spec grav 1.000 0.934 0.878 0.825 0.780 0.739

Lbs/Gall 8.328 7.778 7.296 6.870 6.490 6.151

sample temperature are recorded. The hydrometer value is converted to density at

15.6

◦

C or API gravity at 60

◦

F using standard tables. The API gravity which is always

quoted in Degrees API can be calculated from the hydrometer test at 60

◦

F using the

equation as follows:

Speciﬁc Gravity =

141.5

131.5 +

◦

API

The calculation of the weight per unit volume from the speciﬁc gravity is based on

the US measure of volume (i.e. US Gallons). A summary table of the relationship

between speciﬁc gravity at 60

◦

API, and lbs per gallon is shown as in Table 16.13.

ASTM distillations

There are two types of ASTM distillations that are used in the reﬁnery for plant control

and ﬁnished product quality. These are the ASTM D86 for naphtha and equivalent

and for the kerosenes. D156 is used for the ASTM distillation of atmospheric gasoils

(heating oil and diesel). The major difference between the two tests are the volume

of sample used. In the case of the D86 the sample will be 100 ml while that for D156

the sample will be 200 ml. There are other differences and these will be noted in their

descriptions which follow:

ASTM D86

The diagram in Figure 16.1 is the apparatus used for both ASTM distillations. Only

the apparatus item sizes will change and the temperature levels in the condenser bath.

The measured sample is introduced into an Engler glass ﬂask (A) at 100 ml for the

D86 test. The liquid ﬁlls about two thirds of the ﬂask leaving the space above the

liquid to the cork in the vessel neck as vapor space. About half way along the neck

of the ﬂask there is a vapor offtake tube. The open end of this tube is connected to

the condenser tube which is routed through the condenser bath (B). This condenser

tube emerges from the ‘Bath’and the open end is directed into a measuring cylinder.

For the lighter boiling range samples (i.e. naphthas) this cylinder is placed in a cold

water (slightly below room temperature) bath. The Engler ﬂask rests on an asbestos

or similar plate (F) which has a hole 1”in diameter exposing the bottom of the ﬂask

QUALITY CONTROL OF PRODUCTS IN PETROLEUM REFINING 717

Figure 16.1. Diagram of a typical ASTM distillation apparatus (included in text).

to the heat source. In this case the heat source is shown as a Bunsen burner (C). A

thermometer is introduced into the top of the ﬂask and is positioned so that the bulb

is directly in line with the vapor offtake. The condenser bath is ﬁlled with water and

ice and allowed to reach 32

◦

F before heat is applied to the sample ﬂask and the test

begun. The temperature of the sample is increased slowly until the liquid begins to

boil. The initial boiling point is read as the temperature measured by the thermometer

located in the ﬂask when the ﬁrst condensate drop enters the receiving cylinder (D) at

the end of the condensate bath (B). For light boiling point samples (i.e. naphthas) this

receiver is cooled in a water bath (E). For kerosenes the water bath (E) is not required.

The test is allowed to proceed at a constant rate and temperature readings are taken

at predetermined recovery levels of condensate. (usually these temperatures will be

at 10 vol% recovered, 30, 50, and 90 vol% recovered). When the ﬂask (A) has been

boiled apparently dry, the temperature shown by the thermometer will rise sharply

and then begin to fall. The highest temperature observed in this rise and fall is the

ﬁnal boiling point of the sample.

ASTM D156

The same equipment arrangement is used for this test as for the D86. In this case

however 200 ml of gas oil or diesel sample is used and the ﬂask will be an Engler 200 ml

standard. The other differences are that the hole in the screen (F) has a diameter of 2



The condenser bath contains water at room temperature and the Receiver (D) is a

200 ml measuring vessel, an no water bath is required.

The ASTM distillation curves from all of the methods described above and those in

the determination of vacuum ASTM distillation (not described here as these are not

718 CHAPTER 16

normal marketing or process operation measures) can be converted to TBP and EFV

curves. The methods for such conversions are given in Chapters 1 and 3 of this book.

Such conversions are used primarily for process design and planning.

Flash point test method (D93)

There are two methods used for determining the ﬂash point of an intermediate and

ﬁnished petroleum products. These are the ASTM D56 The Tag Closed Cup method

(commonly known as the ABEL ﬂash point) and the ASTM D93 The Pensky Marten

Closed Cup method. The D56 method is used for material which has a ﬂash of between

◦

F and 148

◦

F while the D93 method is used for all other distillates and residuum

products with ﬂash points above 148

◦

F. Based on this premise the D56 is used almost

exclusively for the kerosene cut range materials. Only the Pensky Marten D93 will

be described here.

ASTM D93

A brass test cup is ﬁlled to an inside mark with the test specimen. A cover is ﬁtted of

speciﬁed dimensions, see Figure 16.2. The specimen is heated and stirred at speciﬁed

rates. An ignition source in the form of a small ﬂame is directed into the cup at regular

intervals. When the specimen is seen to ﬂash, the temperature of the specimen is noted

as the ﬂash point of the sample.

Signiﬁcance and use

The ﬂash point is a measure of the tendency of the, material to form a ﬂammable

mixture with air under controlled laboratory conditions. It is however only one of

several properties that must be considered in assessing the overall ﬂammable haz-

ard of the material. The ﬂash point is used to establish the ﬂammable criteria in

transporting the material. Generally shipping and safety regulations will be based

on the ﬂash point criteria. The ﬂash point should NOT however be used to describe

or appraise the ﬁre hazard or risk under actual ﬁre conditions. This test method

(D93) provides the only closed cup ﬂash point test procedures for temperatures up to

698

◦

Pour point and cloud point (D97)

Pour points are determined initially by heat treating the petroleum specimen above

it’s expected pour point and then to cool the specimen in controlled stages until the

pour point is observed. The pour point is the temperature of the material that it ceases

to ﬂow.

QUALITY CONTROL OF PRODUCTS IN PETROLEUM REFINING 719

Figure 16.2. The Pensky Marten closed cup ﬂash point apparatus.

720 CHAPTER 16

Figure 16.3. Apparatus for pour point tests.

ASTM D97

The apparatus used to determine pour point (and cloud point) consists of a cylindrical

glass jar with a ﬂat bottom a coke stopper at it’s top. A thermometer is inserted

through the coke stopper so that the bulb is immersed up to 3 mm of the capillary

in the specimen. The sample is inserted into the jar up to a prescribed level. The

apparatus is shown in the following Figure 16.3 and is self-explanatory.

The sample is ﬁrst heated as follows:

Material with an estimated pour point above 33

◦

C—heat to a temperature of expected

pour point plus 9

◦

C but at least 45

◦

C in a bath controlled to at least 48

◦

C. Material

with an expected pour point of below 33

◦

C—heat to at least 45

◦

C and cool to 15

◦

in a bath controlled at 6

◦

QUALITY CONTROL OF PRODUCTS IN PETROLEUM REFINING 721

Commence the test then by sequential cooling and observing the ﬂow of the specimen

using cooling baths as follows:

For temperatures down to

Bath 1—Ice and water 9

◦

Bath 2—Crushed ice and sodium chloride −12

◦

Bath 3—Crushed ice and calcium chloride −27

◦

Bath 4—Acetone and solid carbon dioxide −57

◦

The specimen is checked at regular intervals of cooling (every 3–5

◦

C) for ﬂow. This

checking must be done with great care by just slowly tilting the jar to the horizontal

position for not more than 5 seconds, and observing if there is ﬂow. The moving of

the sample from bath to bath should be at the following schedule:

Specimen at 27

◦

C move to bath 1

Specimen at 9

◦

C move to bath 2

Specimen at −6

◦

C move to bath 3

Specimen at −24

◦

C and below move to bath 4.

The reporting of the pour point is the temperature where no ﬂow is observed plus

◦

Kinematic viscosity (D446)

The kinematic viscosity of an oil is obtained by measuring the time required for a

sample of the oil to ﬂow, under gravity through a capillary. The capillary is a part of

the calibrated viscometer and the ﬂow through it of the oil is at a known temperature.

These viscometers are in several sizes and differing design. The conﬁguration and

size of the capillary are calibrated and tested to provide a constant value for that

particular viscometer.

ASTM D446

The viscometer shown in Figure 16.4 is one of many types. It is used for obtaining

the viscosity of transparent liquids. The viscometer shown in Figure 16.4 is des-

ignated a SIL. Its important features and its calibration constant are given in Ta-

ble 16.14.

The viscometer(s) shown may be one of many. These are suspended using a specially

designed holder in a bath containing water with some glycol added to reduce vapor-

ization or prevent boiling. The bath is maintained at a constant temperature at which

722 CHAPTER 16

Figure 16.4. Viscometer for transparent liquids.

QUALITY CONTROL OF PRODUCTS IN PETROLEUM REFINING 723

Table 16.14. Viscometer SIL details

Approximate Kinematic Inside diam of Inside diam of Volume of

Size number constant* viscosity range, cst tube R, mm tubesE&P,mm bulbC,ml

0C 0.003 0.6–3 0.41 4.5–5.5 3.0

1 0.01 2.0–10 0.61 4.5–5.5 4.0

1C 0.03 6–30 0.73 4.5–5.5 4.0

2 0.1 20–100 1.14 4.5–5.5 5.0

2C 0.3 60–300 1.5 4.5–5.5 5.0

3 1.0 200–1,000 2.03 4.5–5.5 5.0

3C 3.0 600–3,000 2.68 4.5–5.5 5.0

4 10.0 2,000–10,000 3.61 4.5–5.5 5.0

∗

Constant is in (mm

/S )/S.

the viscosity is to be reported. The test temperature may be as high as 100

◦

C thus the

use of glycol in the bath water to prevent actual boiling.

The oil sample is introduced into the viscometer through tube L by tilting the viscome-

ter to about 30

◦

from the vertical with bulb A below capillary R. After introducing the

sample attach the viscometer into the holder and insert the viscometer into the bath

so that it is vertical. Allow the sample to reach the bath temperature usually about

30 min before starting the test. Using suction (all laboratories should have a vacuum

system), draw up the sample through bulb C to about 5 mm above the upper timing

mark E. Release the vacuum and allow the sample to ﬂow by gravity. Measure the

time for the sample to ﬂow from the timing mark E to the lower timing mark F. This

is the time t in the equation:

V = C × t

where

V = the kinematic viscosity in centistokes

C = the approximate constant in (mm

/t)/t (from Table 16.14)

T = the ﬂow time from the test.

Reid vapor pressure (D323)

This test is the standard test for low boiling point distillates. It is used for naphthas,

gasolines, light cracked distillates and aviation gasolines. For the heavier distillates

with vapor pressures expected to be below 26 psig at 100

◦

F the apparatus and proce-

dures will be different. Only the Reid vapor pressure for those distillates with vapor

pressures above 26 psig at 100

◦

F are described here. The apparatus used for this test

is given as Figure 16.5.