NOTES ON

Petroleum Processing

David A. Stark

Department of Aerospace and Mechanical Engineering

University of Notre Dame

Notre Dame, IN 46556

Printed on April 30, 1998

Contents

1 Introduction to Petroleum Processing 3

2 Natural Gas and Liquid Separation 7

2.1 Vertical Separators . . . . . . . . . . . . . . . . . . . . . 92.2 Horizontal Separators . . . . . . . . . . . . . . . . . . . . 112.3 Double-Barrel Horizontal Separators . . . . . . . . . . . 132.4 Stage Separation . . . . . . . . . . . . . . . . . . . . . . 13

3 Dehydration 15

3.0.1 Glycol Dehydration Process . . . . . . . . . . . . 183.0.2 Dehydration and Gas Puri�cation by Adsorption 19

4 Cryogenic Processing of Natural Gas 23

4.1 Processes . . . . . . . . . . . . . . . . . . . . . . . . . . 244.1.1 Expander Process . . . . . . . . . . . . . . . . . . 244.1.2 Cascade Refrigeration . . . . . . . . . . . . . . . 27

5 Basic Processes of Liquid Petroleum Processing 31

6 Crude Oil Distillation 35

6.1 Design Tools for Distillation . . . . . . . . . . . . . . . . 376.1.1 True Boiling Point Curve and the Equilibrium

Flash Vaporization Curve . . . . . . . . . . . . . 376.1.2 Establishing Flash Zone Conditions . . . . . . . . 37

7 Vapor Recovery 41

8 Catalytic Cracking 45

1

9 De-waxing Process 49

10 Petroleum Coking 51

10.1 Delayed Coking Process Description . . . . . . . . . . . . 5310.2 Flexicoking Process Description . . . . . . . . . . . . . . 5310.3 Fluid Coking Process Description . . . . . . . . . . . . . 54

A Internal Flow in Pipes 57

B Fluid Machinery 67

B.1 Classi�cation of Fluid Machinery . . . . . . . . . . . . . 67B.2 Turbomachinery Analysis . . . . . . . . . . . . . . . . . . 70

B.2.1 The Angular Momentum Principle . . . . . . . . 70B.2.2 Euler Turbomachine Equation . . . . . . . . . . . 70

B.3 Velocity Polygon Method . . . . . . . . . . . . . . . . . . 75B.4 Performance Characteristics . . . . . . . . . . . . . . . . 78B.5 Dimensional Analysis . . . . . . . . . . . . . . . . . . . . 79B.6 Similarity Rules . . . . . . . . . . . . . . . . . . . . . . . 81

C Compressor Calculations 87

C.0.1 Cylinder Displacement . . . . . . . . . . . . . . . 87C.0.2 Volumetric E�ciency . . . . . . . . . . . . . . . . 88C.0.3 Discharge Temperature and Adiabatic Head . . . 90C.0.4 Power . . . . . . . . . . . . . . . . . . . . . . . . 90

2

Chapter 1

Introduction to Petroleum

Processing

The purpose of this document is to discuss the various componentsof petroleum processing and to look into the thermodynamic and uidmechanic properties found within these processes. The basic purposefor petroleum re�ning is to create usable fuels and lubricants for com-bustion engines, and the e�ect it has had on the modern world is spec-tacular.

Crude oil is composed of literally hundreds of hydrocarbon com-pounds ranging in size form the smallest, methane, which has onlyone carbon atom, to large compounds containing 200 or more carbonatoms. A major portion of these compounds are para�ns. Para�nsare straight-chain hydrocarbon compounds such as methane, ethane,and propane. The remaining hydrocarbon compounds are either cyclicpara�ns called napthenes or aromatics.

These families of hydrocarbons are called homologues, and becauseof the large quantity of these compounds which are found in crude oil,only the simplest of the compounds can be isolated on a commercialscale. Generally, isolation of these compounds are restricted to thosecompounds lighter than C8s. This isolation occurs in the productsprimarily through the use of their di�erent boiling points.

In general, the products that are normally obtained from crude oilcan be grouped as follows.

3

H C

H

H

H

Methane

H C

H

H

C

H

H

H C

H

H

C

H

H

C

H

H

H H

Ethane Propane

C

H

H

C

H

H

C

H

H

H C

H

H

H

C

H

H

C

H

H

C

H

CH H

H

H H

N-Butane

Isobutane

Figure 1.1: Examples of Para�ns in crude oil.

1. Volatile products

� Propane LPG (Lique�ed Petroleum Gas)

� Butane LPG

� Light naphtha (C5s and C6)

2. Light distillates

� Gasolines

� Heavy naphtha

� Kerosene and jet fuel

3. Middle distillates

� Diesel fuel

4

C

H2 C C H 2

C CH2 H 2

H2

C

C CH2 H 2

H2

H2 C C

C

C C

H2

H2 C C

H2

C H 3

C H 3

H

H

Cyclopentane Methylcyclopentane Dimethylcyclopentane

C H 3

H

Figure 1.2: Examples of Naphthenes found in crude oil.

H C

HC CH

HC CH

CH

Benzene

Figure 1.3: Example of an Aromatic hydrocarbon in crude oil

� Heating oils

� Gas oils

4. Fuel oils

� Marine diesel

� Bunker fuels (for ships)

5. Lubricating oils

� Motor

� Spindle

� Machine oils

5

6. Waxes

� Food and paper coating grade

� Pharmaceutical grade

7. Bitumen

� Asphalt

� Coke

Products in these groups are produced from distillation processesand treated to meet certain speci�cations. These speci�cations arethe result of a compromise between performance capabilities of theproduct and the treating that must occur to reach these performancecharacteristics.

6

Chapter 2

Natural Gas and Liquid

Separation

Product from a gas well is composed of a complex mixture of manydi�erent compounds of hydrogen and carbon. This product shall betermed a natural gas well stream or simply a well stream, once it hasbeen introduced to the pipeline for transport. All of the di�erent hydro-gen and carbon compounds found within the well stream have variousthermodynamic properties such as density, vapor pressure, boiling andfreezing points, and other physical characteristics. \Typically, a wellstream is a high velocity, turbulent, constantly expanding mixture ofgases and liquids mixed with free water, water vapor, solids, and othercontaminants." [6, p. 37] As this well stream travels from the hot, highpressure reservoir, it constantly undergoes reduction in its pressure andtemperature. Thus gases separate from and mix with the uids, wa-ter vapor condenses, and various other phases of matter are observedsuch as mist, bubbles, and free gas. Thus one of the most importantand primary steps of processing natural gas is separation of the gasesfrom the solids and liquids in the well stream. This step is convenientlycalled separation.

There are four basic functions a well designed separator must accom-plish. First, it must cause a primary-phase separation between liquidhydrocarbons from gaseous hydrocarbons by creating a momentum re-duction. The second step is a second separation of liquid mist fromthe gases. Then, further re�nement occurs by removing gas suspended

7

in the previously separated liquid. The �nal step is the discharge ofthe separated gas and liquid from the vessel without mixing the newlyseparated products.

Ideally, gases and liquids should reach a state of equilibrium in aseparator, however, the degree of separation usually is dependent on thecost of installation for the separator verses the degree of separation.Thus the processing equipment downstream and the conditions theyrequire dictate the necessary degree of separation.

There are several factors which in uence the design of a separator.The �rst is the ow rate. Flow rates must be accounted for both liquidsand gases entering and exiting the separator. These ow rates are usu-ally measured in barrels per day for liquids and million standard cubicfeet (MMscf) per day for gases. The second factor is the speci�c gravi-ties of the compounds in the well stream. The di�erence in the speci�cgravities will allow for some separation by merely allowing gravity toact on the oil, water, and gases. Thirdly, the required retention timeof the product within the separator for separation. The fourth factoris the operating temperature and pressure of the separator. The nextfactor to consider is the number of phases the separator will handle.In other words, if the separator is designed to be a two-phase design,it handle only oil and gas. On the other hand, a three-phase designwill be capable of separating oil, gas, and water. It should be notedthat the term phase is not used in the standard thermodynamics sense.Rather, it is a term used in the petroleum industry to refer to the typeof product being used. Therefore, the deciding factor for the number ofphases in a separator depends on the content of the well stream. Alsorelated to the content of the well stream is the amount of solid impu-rities the separator must be able to handle. Therefore, for ows withhigh impurity content, the separator must be both easily maintainedand large in size to keep from being clogged. Finally, the amount ofspace allowed for the placement of the separator in uences both the sizeand style of the separator. Thus, this brings us to the three most basictypes of separators: vertical, horizontal, and horizontal double-barrel.

8

2.1 Vertical Separators

Vertical separators are often used for low to intermediate ratios ofgas to oil in a well stream, and they are often employed for well streamswhich produce large slugs of liquid. However, the primary advantageof the vertical separator is the relatively small amount of oor space itrequires. This can become a very important design factor for o�shoreprocessing rigs.

A vertical separator operates by passing the inlet well stream throughan inlet diverter, which is simply a piece of material inhibiting the for-ward velocity of the well stream. By blocking the well stream, thediverter imparts a centrifugal motion to the uid spreading the uidsagainst the separator shell in a thin �lm. This centrifugal motion pro-vides a reduction of momentum in the uid which allows the gases toescape the thin uid �lm. This gas rises to the top of the vessel andthe newly separated liquids settle to the bottom. Any remaining small uid particles, such as mist, which rise with the gas are then caught bya centrifugal ba�e arrangement below the gas outlet. These small uidparticles eventually collect and settle back to the bottom of the vessel.The centrifugal motion imparted by the ba�es ensure the contact ofthe liquid with the ba�es, thus preventing any liquid from escaping.As mentioned above, the vertical separator has a gas outlet above theba�es from which the gas is removed from the vessel to be further pro-cessed. Similarly, there is a liquid discharge at the base of the separatormaintained by a liquid-level control which keeps a set volume of liquidin the base of the vessel. This liquid acts as a seal to force the pressurewithin the vessel to push the gas out of the top of the vessel. Figure2.1 illustrates the basic setup of a vertical separator.

9

Figure 2.1: Standard Vertical Separator

10

Figure 2.2: Standard Horizontal Separator

2.2 Horizontal Separators

In comparison to the vertical separator, the horizontal separatorprovides a much greater gas-liquid interface area allowing the horizontalseparator to handle well streams with much higher ow rates. It alsohas a few economic advantages in that it is less expensive to construct,easier to clean and service, and it is easier to hook up. The basic processwithin the horizontal separator is composed of a few major steps. Firstof all, upon entry into the vessel, the well stream impacts a series ofstaggered ba�e plates which provide an initial momentum reduction.As with the vertical separator, this provides the main component ofthe liquid/gas separation. Gas is then passed along the top of thevessel through horizontal ba�e plates which run the entire length ofthe vessel. Within these horizontal ba�e plates the direction of thegas is altered by a second set of ba�ing plates which create a herring-bone design. The constant change of direction ensures that the liquidparticles, which are suspended in the gas, contact the ba�es and settleto the base of the vessel. To allow the settling process to occur, thehorizontal plates are staggered for drainage. This process of constantlyredirecting the gas is termed scrubbing. The scrubbed gas is then

11

passed to a storage compartment which is connected to the gas outletwhere it can be discharged from the vessel.

The liquid stored in the base of the vessel may either be drained orseparated into oil and water if the separator is three-phase. Located atthe top of this section in Figure 2.2, is an illustration of a horizontalthree-phases separator. The separation of these liquids is based onthe di�erence in the densities of the liquids. Since oil has a lowerdensity than water, it is easily separated by allowing it to oat on topof the water. By maintaining the water level, the oil is allowed to run-over a containment wall into an oil drainage compartment. Similarly,to prevent water from running over the containment wall, there is adrainage site for the water at the base of the vessel.

Figure 2.3: Standard Double-Barrel Horizontal Separator

12

2.3 Double-Barrel Horizontal Separators

Double-barrel horizontal separators possess all of the advantages ofa normal horizontal separator, it uses the same components for thescrubbing process, however, it is capable of handling a much higher liq-uid capacity than the normal horizontal separator. Instead of retainingliquid in the base of the vessel, it is drained directly into the secondbarrel. Thus, the gas velocities may be much higher since over ow ofthe liquids is not as great of a concern.

2.4 Stage Separation

Stage separation is the separation of vapor and liquid phases ofgaseous and liquid hydrocarbons by two or more equilibrium ashes atconsecutively lower pressures. In this context, a ash is the vaporizationof hydrocarbons. A two-stage separation requires one separator andone storage tank. Similarly, a three-stage separation is composed oftwo separators and one storage tank, and a four-stage separator followsthis same pattern. In each case, the tank is considered the �nal stagefor vapor-liquid separation since the �nal equilibrium ash occurs inthe storage tank.

The process occurs by feeding the well stream into the �rst sep-arator, after, the initial separation process has occurred, the gas isremoved from the vessel. By removing the separated gas, the pressurein the vessel is reduced, and the separated liquid is fed into the secondseparator where more gases are released, and so on until the liquid isfed into the storage tank. The purpose of using a stage separation suchas this is that at high pressures, petroleum liquids usually contain highquantities of lique�ed propanes, butanes, and pentanes. Thus by usinga stage separation to lower the pressure on the liquids, a more completeseparation of the products is produced for the storage tank, due to thevaporization of the lique�ed propanes, butanes, and pentanes.

13

14

Chapter 3

Dehydration

One of the most undesirable impurities found within a gas streamis water vapor. Water vapor itself is not a problem, however, the liquidor solid phases which precipitates from the gas during compression orcooling is. In its liquid phase, water accelerates corrosion inside thesystem and acts as an anti-catalyst for later catalytic processes; inits solid state, ice, water can plug valves, �ttings, and even gas lines.Therefore, in order to prevent major di�culties, all fuel gas transportedin pipelines must be at least partially dehydrated.

The quantity of water in saturated natural gas at various pressuresand temperatures can be estimated from Figure 3.1, which is based ondata computed by Kohl and Reisenfeld. [4] This chart also shows ahydrate formation line gas with a speci�c gravity of 0.6. To the left ofthis line, solid hydrates form when the saturated gas is cooled. It canbe noted that hydrates form more readily in gases with a high densitythan gases with a very low density.

For example, when examining the chart, at a pressure of 1000 psia,hydrates form at approximately 62�F in a natural gas with a speci�cgravity of 0.6. However, for a speci�c gravity of 0.75 and 1.00 hydratesform at temperatures of 67�F and 71�F respectively. [4, p. 583]

One of the contributing factors which increases the equilibrium con-centration of water in the gas stream is the presence of substantial con-centrations of acidic gases. Two such acidic gases are carbon dioxideCO2 and dihydrogen sul�de H2S. The e�ect of these gases is most no-table at pressures above 1000 psia. Typical data for this correlation is

15

Figure 3.1: Water-vapor content of saturated natural gas

presented in Table 3.1. It is noted that the increase of the concentra-tion of water caused by acidic gases is greatest at high temperaturesand low pressures. The e�ect of CO2 verses the e�ect of H2S is notequivalent, though for equal concentrations, CO2 contains only 75 % ofthe water concentration of H2S.

16

Pressure (psig) Temperature (�C) H2S (%) CO2(%) H2O Conc. (ppMM)1000 100 0 0 58.91000 100 10 10 63.91000 100 20 20 71.91000 200 0 0 6301000 200 20 20 7336000 100 0 0 23.16000 100 10 10 38.56000 100 20 20 73.66000 200 0 0 1976000 200 20 20 39710000 100 0 0 19.910000 100 10 10 36.110000 100 20 20 71.810000 200 0 0 15910000 200 20 20 378

Table 3.1: E�ect of H2S and CO2 on Water Vapor Content of SaturatedNatural Gas

The water content of saturated air at pressures from 1 to 1000 atmis given in Figure 3.2, which can be found in the Chemical EngineersHandbook.

Another useful method of indicating the water content of a gas is interms of its dew point. The dew point is a more direct indication of thedehydration e�ectiveness than the absolute water content. Therefore,if the dew point temperature is known, given either the variable forpressure or content of the water, the other variable may be read fromFigure 3.1.[?].

There are three primary processes for water vapor removal from gasstreams, and they can be classi�ed as follows:

� Absorption by Liquids

� Adsorption by Solid Desiccants

17

100

101

102

103

10−7

10−6

10−5

10−4

10−3

10−2

10−1

100

LBS

Wat

er/L

BS

AIR

PRESSURE, ATMOSPHERES

100

150

50

0

-50

Figure 3.2: Water-vapor content of saturated air

� Condensation by Compression and/or Cooling

Only absorption and adsorption will be considered in this documentsince condensation is rarely an economical means of water vapor re-moval. There are three primary liquids used for drying gas: triethy-lene glycol (TEG), diethylene glycol (DEG) and tetraethylene glycol(T4EG).

3.0.1 Glycol Dehydration Process

Figure 3.3 represents a ow diagram of a plant designed to useeither of the glycols for the dehydration process. The basic steps thatoccur are as follows. First, the glycol stream containing from aboutone to �ve percent water contacts the gas in a short, counter-currentcolumn. The water which is absorbed dilutes the glycol. This dilutedsolution must be re-concentrated before it can be forwarded to the

18

InletScrubber

Absorber Reconcentrator

Phase Separator

H2O

Dried Gas

Figure 3.3: Flow Diagram of a Glycol Dehydration Plant

absorber. Re-concentration of this glycol is achieved by distilling waterout of the solution in a regenerator. This method of re-concentrationby heating the solutions is very e�ective due to the large di�erence inboiling points of water and glycol. This is a cyclic operation, wherethe glycol is repetitively diluted and re-concentrated. Eventually, theglycol is broken down, and it must be replaced.

3.0.2 Dehydration and Gas Puri�cation by Ad-

sorption

Anytime a molecule bonds to the outside of a compound, the processis termed adsorption. This is di�erent from absorption in that duringabsorption, the molecule penetrates the compound. In the process of

19

adsorption, materials are concentrated on the surface of a solid as aresult of forces existing at this surface, whether the forces be pressure,weight, or other intermolecular forces. The greater the surface area ofthe adsorption material or dessicant, the greater amount of particlesor impurities adsorbed. Therefore, most solid dessicant adsorbers usedessicants that are irregular granules or preformed spheres or tabletsin order to increase the surface are of the dessicant.

The cause of the inter-particle force, is not thoroughly understood,however, the most familiar theory proposed in Kohl and Reisenfeld [4]is that the forces are similar to those responsible for chemical reactions.Adsorption resembles sites of residual valency found with many crystals.When an adsorbable molecule, in this case a water molecule, comesin contact with an unoccupied space on the desiccant, the moleculebecomes trapped due to the bonding forces and cannot rebound intothe gas. However, molecules which are trapped may also become freeof the desiccant when suitably activated by raising its energy level.However, after the molecule becomes activated, another molecule maytake its place in the now unoccupied site.

Although adsorption can be practiced with many solid composi-tions, the majority of gas puri�cation and dehydration uses forms ofsilica, alumina, carbon, and silicates. The silica and alumina-base ad-sobents are primarily used for the removal of water molecules. However,whether the process involves the removal of water vapor or of some otherimpurity, the basic concepts involved in adsorption are the same.

In its simplest form, an adsorption plant for removing water vaporfrom gases consists of two vessels �lled with granular desiccant. Thesetwo beds are connected in such a way that gas may be passed throughone vessel while the other vessel's desiccant is regenerated. Regenera-tion of the desiccant occurs by passing hot gas through the desiccantmaterial which activates the water molecules, freeing them from thematerial. This separated water vapor may be removed from the vesseland it is ready to accept gas again.

Many gas-dehydration problems can be solved using either liquidremoval systems or by using solid desiccant. However, the principaldesign factor depends on whether complete or nearly complete dehy-dration is necessary. For this case, solid desiccant designs are moreappropriate. On the other hand, for the dehydration of relatively large

20

volumes of high-pressure natural gas, a liquid dehydrating system ismore applicable since it can be run continuously.

21

22

Chapter 4

Cryogenic Processing of

Natural Gas

Cryogenics is a branch of thermodynamics dealing with the e�ectsand creation of very low temperatures. The temperatures that areassociated with cryogenics are generally below �150 F. However, inthe petroleum industry, cryogenic temperatures are considered to bebelow �50 F. The reason for this is that -50 F is approximately theminimum temperature that can be reached with a propane refrigerationsystem.

The key to cryogenic gas processing is using the proper combina-tion of pressure with low temperature. When the proper combinationis achieved, a very complete product recovery can be made. Figure 4.1represents an example of the relationship between pressure and tem-perature with the recovery of 60 percent ethane from natural gas.

23

100 150 200 250 300 350 400 450 500 550 600−190

−180

−170

−160

−150

−140

−130

−120

Tem

pera

ture

(F

)

Pressure (psia)

Figure 4.1: Pressure and Temperature to Recover 60 percent Ethane(Data taken from Gas Processors Association [5])

4.1 Processes

4.1.1 Expander Process

Figure 4.2 represents the ow for an expander process. The �rstprocess applied to the inlet gas is the removal of water. This is doneby cooling the gas through a two branch process. The inlet gas isdivided such that approximately half ows through a gas/gas exchangerwhere cooling is accomplished by using cold residue gas, and the secondhalf ows through a cold demethanizer internal liquid found on the

24

1 2

3

GasInlet

InitialTreating First

Gas/GasExchanger

Second Gas/GasExchanger

ExpanderInletSeparator

SideExchange

Demehtanizer

Demethanized PlantProducts

FinalProduct

Recompressor

Expander

Exp.- Compressor

Figure 4.2: Cryogenic Expander Process

side exchange of the demethanizer unit. The gas from these �rst twoprocesses are then joined to ow through a second gas/gas exchanger.Liquid from the gas is condensed and separated from the vapor in anexpander inlet separator. The vapor ows through the expander, wherethe pressure is reduced. This liquid is then fed to the demethanizer.Once the pressure has been reduced, the vapor continues to ow to thetop of the demethanizer. The demethanizer has a large top which servesas an expander outlet separator. Cold residue gas from the top of thedemethanizer then acts as a coolant for inlet gas. It is then compressed

25

to sales gas pressure in the expander-compressor and recompressor.Figure 4.3 represents the pressure-temperature diagram for the ex-

pander process. In this process, the solid line refers to the plant inletgas. To the right of the critical temperature and pressure point is thedew point line. To the right of the dew point line, and outside of thisline, the gas is 100 percent vapor. However, as the gas is cooled, at areasonable pressure below approximately 1200 psia the gas begins tocondense. As the gas is cooled further, it reaches the dew point linewhich is located to the left of the bubble point line, and outside ofthis line, the gas condenses completely. The dashed line represents theprocess represented in �gure 4.2

Downstream of the initial treating facilities, the inlet gas is repre-sented by point 1 on both �gures 4.2 and 4.3. As the gas is cooled in thegas/gas exchangers and the demethanizer side exchanger, the tempera-ture is lowered to point 2. At point 2, the gas enters the expander inletseparator where the condensed liquid is separated from the vapor. Thisvapor has its own pressure-temperature diagram, and it is representedby the dashed curve. At the expander inlet, the gas is on its dew pointline.

As the gas ows through the expander, its pressure-temperaturepath is shown by the dashed line from point 2 to point 3. Where point3 represents the gas at the outlet of the expander. The importance ofdoing driver work for the compressor can be seen by comparing path 2to 3 with path 2 to 4. Path 2 to 4 is called a Joule-Thompson expansion,where the gas is simply expanded without doing any work. It can beseen by comparing these two paths that both the outlet pressure andtemperature are higher for the Joule-Thompson expansion. This resultsin a reduction of product recovery.

26

-200 -100 1000

100

1000

800

200

300

500

Bubble Point Line

Critical Temperatureand Pressure

Dew Point Line

2 1

34

Figure 4.3: Pressure-Temperature Diagram for Expander Process (Datataken from Gas Processors Association [5])

4.1.2 Cascade Refrigeration

Figure 4.4 represents a ow diagram for a the principle componentsof a cascade refrigeration process. The use of a cascade refrigerationprocess is normally limited to processing inlet gas steams around 500psig or lower. Higher pressures in the gas result in a large quantity ofmethane gas to condense.

After initial treating, the inlet gas is cooled by cold residue gasand then sent into the refrigeration system. The cascade refrigerationsystem is composed of two primary systems, the propane chiller andthe ethane chiller. Propane is used as the �rst chiller, this is due tothe fact that propane can be condensed at fairly low pressure by air orwater coolers. The condensed propane is then used to cool the inlet gas

27

PropaneSurgeTank

PropaneCondenser

PropaneCompressor Ethane

Compressor

EthaneCondenser

Ethane Surge Tank

Separator

Liquid toDemethanizer

PropaneChiller

EthaneChiller

SecondGas/GasExchanger

Residue GasFor Sales

InletGas

Figure 4.4: Cascade Refrigeration

to approximately �40 F, causing separation of most of the undesiredcomponents of the gas.

Stage two of the cascade refrigeration process is the ethane chiller.Ethane is used in the second stage to cool the inlet gas to a temperaturearound �120 F. Cooling the inlet gas to this temperature range knocksout the remaining undesired components of the gas, leaving the endproduct to be fairly pure. The ethane used in the second stage of therefrigeration process is compressed and then chilled by the propanestream at the ethane condenser.

Thus, the propane refrigeration system is used to cool both theinlet gas in stage one and to condense the ethane used in stage two. Byoptimizing the cooling done on the inlet gas by the propane, the amountof ethane used in stage two is minimized. Finally, by minimizing the

28

quantity of ethane used in stage two, the amount of propane is alsominimized for condensing the ethane.

MethaneCompressor

PropaneCompressor

EthyleneCompressor -155 F

-265 F

-80 F490 psia

Stream 2

Stream 1

90 F500 psia

85 F

85 F

85 F

Stream 3

-40

Figure 4.5: LNG Cascade Cycle

A more speci�c type of cascade cycle is the Lique�ed Natural Gas(LNG) cascade cycle represented in �gure 4.5. The system is composedof a heat exchanger, and three refrigerants. The primary refrigerationsystem used in this system is propane. Following the �rst stage is anethylene chiller, and the �nal refrigeration system used is methane.The heat exchanger uses an aluminum plate �n, aluminum core or analuminum tubing which is wound on an aluminum spool. These twodesigns require many di�erent ow streams. The di�culty arises in thatit is very di�cult to maintain these di�erent ow streams with shell-and-tube exchangers. Thus there is the need for this design. The �rst

29

stream, Stream 1 is the gas entering the system to be lique�ed. The gasis dehydrated before entering the system and coming in contact withthe plate �n exchangers. As it is cooled within the system, most of theheavy ends are condensed, knocking them out of the gas. These heavyends are then removed through a separator at a temperature around�80 F. This is represented by Stream 2 in �gure 4.5. As the ow streamcontinues through the heat exchanger, nitrogen, methane, ethane, andsome propane are lique�ed around the temperature of �250 F and 20psia. These are then removed as Stream 3, completing the separation.

Through the use of cryogenic processes, many more hydrocarboncompounds can be separated in comparison to the use of separatorsalone. Thus, a much more pure product which results in a higherheating value is produced.

30

Chapter 5

Basic Processes of Liquid

Petroleum Processing

Oil enters a re�nery from two main sources, crude oil directly fromthe well and from liquid product separated from natural gas. In re�ningthis crude oil, it is �rst broken up into various raw stocks, which arethen re�ned into a �nished product. This break-up of the crude oilis achieved by separating the crude through a series of boiling points.This is accomplished within the atmospheric and vacuum distillationunits.

Crude oil �rst enters the atmospheric distillation unit where dis-solved brine is removed in a process referred to as De-salting and itis heated to a predetermined temperature to begin the fractionationprocess. This is done through heat exchange with hot products as wellas direct-�red heaters. The now hot and partially vaporized crude oilis \ ashed" in a distillation unit, commonly known as a fractionationtower.

The fractionation tower separates the crude into four basic prod-ucts: kerosenes, light gas oil, fuel oil, and heavy gas oil. Once theseproduct have been separated they can be passed along to the next levelof processing. For example, kerosenes and light gas oils are passed alongto vapor recovery units and catalytic cracking units. From here theyare processed further to create gasoline, jet fuel, heating and diesel fu-els, and industrial fuel oil. Heavy gas oils are passed along from thefractionating tower to extraction and dewaxing units, after which it is

31

processed into lubricating oils and greases. Finally, crude residue isprocessed into petroleum coking and asphalts.

Further break-up of crude oil is often required to produce low-costfeed for cracking units or it may be necessary for the basic stocks forlubricant production. In either case, a vacuum distillation unit is in-serted into the re�ning system. During this process, products from theatmospheric distillation unit is fed into the vacuum distillation unitwhere it is distilled under sub-atmospheric conditions. This unit oper-ates similarly to the atmospheric unit in that the crude that is fed intothe unit is heated by heat exchange between heaters and hot products.However, the vacuum unit operates at overhead pressures as low as .02psig, where the atmospheric unit operates at a positive pressure of 5 to10 psig. Under these conditions the hot vapors rise to the top of thefractionating tower, where they are condensed. The condensed prod-ucts are then taken from the tower in side-streams. After the vacuumdistillation process, there are three resulting products: light vacuumgas oil, heavy vacuum gas oil, and bitumen.

32

IndustrialFuel Oil

Waxes

Lube Oils

Greases

Asphalts

Petroleum Coking

Coking

Extraction Dewaxing

CatalyticCracking

VaporRecovery

Alkylation

Grease Manufacturing

Gasoline

Jet Fuel

Diesel Fuels

AdditionalProcessing

Fra

ctio

natio

n T

ower

Figure 5.1: Overview of Re�nery Flow

33

34

Chapter 6

Crude Oil Distillation

The concepts for crude oil distillation are primarily the same forboth atmospheric and vacuum distillation units. However, this sectionwill only deal with the fractionation tower of the atmospheric distilla-tion unit. The degree of fractionation in a crude oil distillation unitis measured by the temperature di�erence between 95% vol. ASTM(American Standard Temperature and Measurement) of the lighterproduct and 5% vol. ASTM of the adjacent heavier product. Theselighter products are composed kerosene and light gas oil. The heavierproducts are composed of heavy gas oil and fuel oil. When the temper-ature di�erence gives the 95% point of the lighter products to be lessthan the 5% point of the heavier products, the di�erence in tempera-tures is referred to as an ASTM gap. For the reverse case, the situationis referred to as an ASTM overlap.

Fractionation performance is at its best when there is an ASTM gapbetween the products. As fractionation decreases, the gap becomes anoverlap, a greater number of the components of the two products arenot separated. Fairly complete fractionation may be expected in theupper regions of the fractionation tower between lighter products suchas kerosene and light gas oils. However, lower in the fractionationcolumn such separation is not possible. It may be pointed out, that inthe lower levels of the fractionation column, there is an ASTM overlap.

During crude oil distillation steam stripping is used to further re-move the entrained light end products from the draw-o� products.When side stream products are drawn o� of the main fractionation

35

Figure 6.1: Fractionation Curves

column it contains various light end components from vapors passingthrough the draw-o� trays. This draw-o� product is then routed toa side-stream stripper where steam is introduced through the bottomof the tower, owing counter-currently to the liquid. By imposing acounter current ow of the steam on the liquid, greater heat transfer isachieved due to a mixing of the products.

Steam strippers such as the one described are usually composed offour trays to increase surface area contact between the products andthe steam. The entrained light ends are removed by the steam throughvaporization and both they and the steam reenter the fractionationcolumn. This process is also done for the residue collected from the baseof the fractionation column as well. A representation of the quantity

36

of steam and the percent of light end products removed by stripping isrepresented in the Figure 6.1.

6.1 Design Tools for Distillation

6.1.1 True Boiling Point Curve and the Equilib-

rium Flash Vaporization Curve

Two important tools for designing and maintaining the distillationprocess are the True Boiling Point (TBP) and the Equilibrium FlashVaporization (EFV) curves. The �rst of these is the TBP curve whichis created from the product ASTM distillation curves.

The ASTM distillation data is tabulated as the temperature's InitialBoiling Point (IBP), 10%, 30%, 50%, 70%, 90%, and Final Boiling Point(FBP). The temperatures between the IBP and the EBP are read o�at the respective volume percentages distilled. This is represented inFigure 6.2. From such a �gure, data for the TBP may be read.

Once TBP has been calculated, the EFV curve may be created. Thepurpose for creating an EFV curve is that it provides the temperaturewhere a required volume of product will be vaporized. This informationis very important in the design stage, in that improper design will eitherprovide insu�cient separation or unneeded costs.

Using Figure 6.3 the Flash Reference Line (FRL) may be drawnonto the TBP curve. The EFV is then drawn as a straight line betweenthe intersection of the 10% volume point on the FRL and the 70% volpoint on the TBP curve.

6.1.2 Establishing Flash Zone Conditions

A ash zone is the area in the crude distillation tower where separationof distillate vapors from unvaporized liquid product occurs. Upon entryof the ash zone, vapors from the distillate rise through the tower whereit is condensed by a cold re ux stream. This re ux stream ows downfrom the top of the tower. At the same time, steam enters the ashzone from the bottom product stripper which is located below the ashzone.

37

Flash zone conditions, particularly the temperature, are di�cult tomeasure accurately. This is primarily due to the turbulent conditionscreated by the entrance of the liquid products and the disengagementof the vapors from the liquid products. However, these conditions arenecessary for evaluating a distilling units performance. Therefore, thereare seven primary steps for determining ash zone conditions given byJones.[3]

� Establish the total ash zone pressure.

� Set the quantity of stripping steam used. (This value is usually1.2 pounds of steam per gallon of product)

� Using a material balance, calculate the moles per hour of vaporleaving the ash zone.

� Set the amount of over- ash

� Construct the EFV curve.

� From a knowledge of the amount of hydrocarbon vapor moles, themoles of steam in the ash zone, and the total pressure within the ash zone, determine the partial pressure of hydrocarbons. Thisis

molesHCvapor

molessteam +molesHCvapor� totalpressure (6.1)

� Adjust the EFV curve to calculate partial pressures.

By following this seven step process, the ash zone temperaturemay be obtained.

38

Figure 6.2: True Boiling Point Correlation

39

Figure 6.3: Slope for TBP

40

Chapter 7

Vapor Recovery

After light-end vapors are removed from the crude feed in the frac-tionation tower, they are removed through an outlet in the top of thetower. These vapors are then condensed into a liquid phase for furtherprocessing.

water

light-ends

water inwater out

Steam andLight end Vapor

Liquid waterand Light ends

Containment for Water Drainage

Condenser

Figure 7.1: Water Cooler Condenser

To begin the condensing process these vapors are passed througha cold water condenser which speeds the phase change of the light-ends. The �rst phase of this process is a heat transfer, whereby the

41

gas is passed over coils containing counter current owing water. Heatfrom the vapor passes to the coils and is removed by the owing wa-ter. The heat transfered to the water is then removed by convectionand radiation to the atmosphere. As the temperature of the vapordecreases it begins to condense, eventually reaching a nearly completeliquid phase. Once this occurs, the water that has condensed from theextracted steam may be drained o� from the light-end liquid. After thisseparation of liquids, the light-end liquids may be further processed toproduce jet fuels, gasoline and diesel fuels.

The driving principle behind this condenser is that of a heat ex-changer. Where in this case, heat from the vapor is transfered throughconvection, due to the velocity of the vapor, to the coil. There is thena heat transfer across the thickness of the coil due to conduction, andthen there is a transfer to the liquid water inside the coils due to con-vection. Finally, there is a very small amount of heat that is removedby radiation e�ects within the system.

The heat transfer within the system follows the equations:

_Q = �kAdT

dx(7.1)

_Q = hA(Tb � Tf ) (7.2)

_Q = ��ATb4 (7.3)

where k is the conduction constant based on the properties of themedium, h which is a convection constant based on the velocity andproperties of the medium, � which is the emissivity of the surface of theradiating medium, and � which is the Stefan-Boltzmann constant.

The heat loss by the vapor results in an enthalpy loss in the vapor:

dH

dt= _Q� _W (7.4)

where enthalpy, H, is the sum of the internal energy U and theproduct of the pressure p and volume V , giving an equation for enthalpyas:

H = U + pV: (7.5)

42

Vapor

Solid

Liquid

Temperature

Pre

ssur

e

Figure 7.2: Pressure vs. Temperature Phase Relationship

Since U, p, and V are all properties of the vapors, this combinationH is also a property of the vapor. It should also be noted that in theenthalpy balance, _W for the system is zero. Thus, the vapor performsa phase change to a liquid state, and removed energy is then releasedto the atmosphere by the owing water.

43

44

Chapter 8

Catalytic Cracking

Catalytic processing is designed to improve the octane quality ofmedium to light end products. By increasing the octane level, the ten-dency to ignite prematurely is decreased. This is both advantageous tothe environment and the machinery. The principle reaction is dehydro-genation of aromatics or naphthenes, which can then add para�n sidechains in place of some of the hydrogen attached to the ring of carbons.Examples of such para�ns, aromatics and naphthenes may be found in�gures 7.1, 7.2, and 7.3.

The combination of the para�ns to the naphthenes or aromaticsresult in octane chains which take the basic form found in �gure 7.4.

Feeds for this process are passed through three basic stages. Eachstage contains two operations, a pre-heat and then a reactor. Thereactions in this �rst stage are highly endothermic, in that heat is addedin order for the reaction to occur. The mixture is then passed from thereactor to a re-heat before passing to the second reactor, and �nally toa third re-heat and reactor. The second and third reactions are alsoendothermic, however, it is to a slightly lesser degree since there arefewer reactants to react. The product is separated into hydrogen-richgas and reformate in a high-pressure separator which operates arounda temperature of 100oF .

Typically, the dehydrogenation process occurring inside the reactorsis due to chloride or platinum catalyst, and by pre-heating the liquidproducts, a higher internal energy is created to spur the reaction. Typi-

45

H C

H

H

H

Methane

H C

H

H

C

H

H

H C

H

H

C

H

H

C

H

H

H H

Ethane Propane

C

H

H

C

H

H

C

H

H

H C

H

H

H

C

H

H

C

H

H

C

H

CH H

H

H H

N-Butane

Isobutane

Figure 8.1: Examples of Para�ns in crude oil.

cally these catalysts have approximately a one year lifespan, after whichthey must be replaced. After passing through these three reactors, theproduct is passed to a separator to remove more light ends, which arepassed on to the vapor recovery unit. The remainder of the productis further processed to create industrial fuels which are used to powerheavy machinery for the generation of electricity.

46

H C

HC CH

HC CH

CH

Benzene

Figure 8.2: Example of an Aromatic hydrocarbon in crude oil

C

H2 C C H 2

C CH2 H 2

H2

C

C CH2 H 2

H2

H2 C C

C

C C

H2

H2 C C

H2

C H 3

C H 3

H

H

Cyclopentane Methylcyclopentane Dimethylcyclopentane

C H 3

H

Figure 8.3: Examples of Naphthenes found in crude oil.

C

C

C

C

C

C

C

C

H

H

H

H H H H H H H

H

HHH H H HH

Figure 8.4: Octane Carbon Chain

47

Re-heater Re-heaterPre-heater

Reactor 1 Reactor 2 Reactor 3

Separator

LightendFeed

Figure 8.5: Catalytic Reactor Process

48

Chapter 9

De-waxing Process

"Warm Solution Drum"

(High Pressure)

Batch Cooler Rotary Filter

Refrigeration System

PropaneInjection

Solvent Recovery

Filtered Oil

Waxy MixtureWax

Dewaxed Oil

Feed Oil

Figure 9.1: De-waxing Process Flow Diagram

49

Most lubricating oil feed stock must run through a De-waxing pro-cess in order to ow properly at ambient temperatures. Therefore,De-waxing is one of the most important processes in the manufactur-ing of lubricating oils and grease. The simplest and most commonDe-waxing process uses refrigeration to crystallize wax which permitsa rapid �ltration of the wax from the oil.

In a propane De-waxing process, propane is used as both a dilutantand a refrigerant for the waxy oil mixture. By injecting propane intothe oil stream the waxy oil mixture is thinned, and the propane acts asa transport medium for the wax as it begins to crystallize.

Once waxy oil is mixed with the liquid propane it is allowed to coolto a temperature of approximately 80oF (27oC). It is then pumped intoa \warm solution drum" where it is pressurized to prohibit propanevaporization. From the solution drum, it is charged into a batch coolerwhere the mixture is cooled at a controlled rate by evaporation of thepropane. As a refrigerant, propane cools the oil through evaporationfrom the now propane-waxy oil solution. The cooling process usuallyoccurs at a rate of approximately 3oF (1:5oC) per minute, and the ratioof the volume of propane to feed oil ranges between 1:5 : 1 and 3 : 1.This rate is carefully controlled to promote good wax crystal growth.

Wax is then removed form the oil using rotary �lters which collectthe wax into large clusters. These clusters are then removed by passingcold propane vapors over the wax, causing the wax cluster to contractand release from the �lter.

Propane is then recovered from the De-waxed-oil stream by heatingthe stream to temperatures around 320oF (160oC) causing the propaneto vaporize. These propane vapors are then ashed at high pressureso that the propane can be condensed with cooling water. Once re-condensed, it is recirculated into the the waxy oil streams to repeatthe process. The De-waxed lubricating oil is then sent to a �nal re-formulation process to stabilize the color and odor of the lubricant.Afterwards, the processed oil may then be used in industrial processesas lubricating oils or industrial grease.

50

Chapter 10

Petroleum Coking

Heavy residual products which accumulate at the base of the frac-tionation tower have become more of a problem for petroleum re�neries.This is primarily due to the decrease in demand for heavy residual fu-els. Historically these residual fuels were burned to produce electricalpower for industrial operations. However, heavy environmental restric-tions have led industries to switch to natural gas. As a result, more ofthis residual product must be processed in order to have a marketableproduct. To combat this problem, coking units are introduced to con-vert these heavy products into a solid coke and to lower the boilingpoints of other hydrocarbons. These hydrocarbons can then be pro-cessed in other re�ning units for conversion into fuels of higher value.The other product of this process is solid coke which is primarily solidcarbon mixed with various metallic impurities.

The coking process is very similar to an extreme case of crackingwhere one of the end products is coke. This coke actually containssome volatile matter which is remaining hydrocarbons with high boilingpoints. These hydrocarbons must then be removed by running the solidcoke through a calcination process at approximately 2000�F to 2300�F(1095 to 1260 �C).

The need for a coking process is to create a more suitable feed fuel forthe catalytic cracking process. By reducing coke formation inside thecatalytic cracker, re�neries have an increase in the output of catalyticcracking processes, and thus produce fuels at a much lower cost.

There are three primary coking processes in use today. The �rst of

51

these is delayed coking, which is the most widely used process. Fluidcoking and Flexicoking process are two other methods developed byExxon and are now being commercially operated in a handful of re-�neries.

There are several types of coke produced in these processes. Cokeproduced in the delayed process is primarily sponge coke. Sponge cokeis hard, porous and irregularly-shaped, and it receives its name becauseit resembles a sponge. Sponge coke ranges in size from 20 inches to a�ne dust. A second form of coke produced in the delayed process isneedle coke. Needle coke takes its name from its needle-like crystallinestructure. Both of these cokes have uses in the production of electrodesdue to their low electrical resistivity and a minimal change in thermalexpansion. A third and less desirable form of coke is shot coke. thisform of coke takes its name from its spherical shape giving it a similarappearance to shotgun pellets. Shot coke is an undesirable productdue to its lack of marketability and the danger it creates by posing thethreat of plugging the coking unit.

The main uses of petroleum coke are:

� Fuel

� Chemical carbon source for manufacturing of carbide

� Manufacturing of electrodes

� Manufacturing of graphite.

52

10.1 Delayed Coking Process Descrip-

tion

In the delayed coking process residual heavy products are heatedto temperatures around 925�F. The heated residual product isthen fed to one of several coking drums represented in Figure10.1. Upon entry into the drum, vapors released from the heatedcoke are extracted through the top of these drums and returnedto the fractionation tower. Once the coke drum in service is �lledto a safe margin from the top, the heater e�uent is switched tothe empty coking drum. This safe �ll height for the drum is setby the designer of the particular drum. Once the drum is isolatedfrom the heater, the coke drum is steamed to remove remaininghydrocarbon vapors in the coke through a calcination process.These hydrocarbon vapors are then removed through the top ofthe coke drum as was done before, leaving only the solid coke inthe drum. After the calcination process is completed, the solidcoke is quenched with water. This water is then drained from thedrum, and the coke is ready for removal. Removal of the cokeis accomplished through the use of either a mechanical drill orreamer. After which the coke may be shipped for manufacturingof various products.

10.2 Flexicoking Process Description

In the exicoking process, feed from the fractionation tower ispreheated and sprayed into the reactor where it contacts a hot uidized coke. this uidized coke is cycled between the reac-tor and the heater at a rate which maintains a reactor temper-ature around 1000�F (540�C). The cracked vapor products arethen passed through ba�es in a scrubber located in the top ofthe reactor to separate the coke particles from the vapors. Thisscrubber is fed a cool oil wash which washes the collected par-ticles back to the lique�ed coke in the reactor. The extracted

53

vapors are then removed from the reactor scrubber and returnedto the fractionation tower where they are sent to various re�neryprocesses.

As the coke cools inside the reactor it settles to the base of thereactor, this settling coke is then stripped with steam in a ba�edsection of the base of the reactor to prevent products other thancoke from leaving the reactor. Coke then ows from the reactor tothe heater where it is reheated to approximately 1000�F (540�C).The reheated coke then ows from the heater to a third uidizedbed referred to as a gasi�er. In the gasi�er, the coke is reactswith air and steam to produce various fuel gases which consistof CO2, CO, H2, and N2. This gas is then removed from thegasi�er and passed through a scrubber before being sent to bereprocessed in the fractionation tower. The remaining purge cokeis then treated and removed from the process for manufacturingof coke products.

10.3 Fluid Coking Process Description

Fluid coking is a simpli�ed version of exicoking. In the uidcoking process, there are only two main components, a reactorand a heater. This di�ers from the exicoking process in thatthere is no gasi�er. Thus the uid coking process has a disad-vantage compared to the exicoker in that less hydrocarbon gasis removed and saved, however, this comes at an advantage inlower cost. Therefore, a uid coking system would be used inproducts containing low amounts of hydrocarbons found withinthe residual heavy products.

54

Heater

Cok

e D

rum

Cok

e D

rum

Coke

Extracted Gas

IndustrialFuel Oil

Waxes

Lube Oils

Greases

Asphalts

Extraction Dewaxing

CatalyticCracking

VaporRecovery

Alkylation

Grease Manufacturing

Gasoline

Jet Fuel

Diesel Fuels

AdditionalProcessing

Fra

ctio

natio

n T

ower

Figure 10.1: Delayed coking unit.

55

Reactor

Products toFractionation Tower

Feed

Steam

Heater

Gasifier

Coke

Purged Coke

Coke

Gas

(Scrubber)

(Scrubber)

Figure 10.2: Flexicoking coking unit.

56

Appendix A

Internal Flow in Pipes

Flows completely bounded by a solid surface are called internal ows. This ow can be either laminar or turbulent, compressibleor incompressible depending on the velocity and the nature of the uid. For most petroleum uids, ows will be considered incom-pressible. Therefore, in the case of incompressible ow througha pipe, laminar or turbulent ow is determined by the Reynoldsnumber. The Reynolds number is a dimensionless parameter thatrelates the ratio of internal forces to viscous forces, and it can beexpressed as the following equation:

Re =� �V D

�(A.1)

where:

{ Re=Reynolds number

{ � = density of the uid

{ �V = the average ow velocity

{ � =the viscosity of the uid

Laminar ow is characterized by little or no mixing of the owing uid, and the velocity pro�le as seen in �gure A.1 is parabolic.

57

Turbulent ow involves complete mixing of the uid and a moreuniform velocity pro�le. An ideal representation of the velocitypro�le is also represented in �gure A.1. Laminar ow has beenshown in experiments to exist at Reynolds numbers below 2300and turbulent ow above Reynolds numbers of 4000. Reynoldsnumbers between these limits are considered to be in a transi-tional zone and can be either laminar or turbulent.

Once the ow regimes have been calculated, pressures within thepipes may be determined using Bernoulli's theorem. Bernoulli'sequation expresses the properties of the owing uid in terms ofthe energy contained within a uid. Using this basis, Bernoulli'sequation breaks down the energy in the uid in terms of:

{ The height of uid above an arbitrary datum

{ The potential energy from the pressure of the uid at a pointalong the pipe

{ Kinetic Energy from the velocity of the uid

Assuming no work is done by the uid and no energy is added toit, the law of conservation of energy may be applied. Thus, theenergy at a point along a pipe must equal the energy at a secondpoint in the pipe. Bernoulli's equation can therefore be writtenas

P1

�+V1

2

2+ gz1 =

P2

�+V2

2

2+ gz2 (A.2)

where:

{ z=elevation

{ P=pressure

{ � = density of the uid

{ V = velocity

{ g =the gravitational constant

58

However, in pipe ow, there is energy loss due to friction, andthus, Bernoulli's equation may be rewritten as

P1

�+V1

2

2+ gz1 =

P2

�+V2

2

2+ gz2 + hlT (A.3)

where hlT is the total head-loss. This total head loss is the sumof all major losses, hl, due to friction and the sum of all minorlosses, hlm, due to entrances, �ttings and area changes. Thus:

hlT = hl + hlm (A.4)

where:

hl = fL �V 2

D2(A.5)

where:

{ f=the friction factor

{ L= Pipe length

{ D= Inner pipe diameter

{ �V= Average uid velocity

and

hlm = fLe

�V 2

D2(A.6)

or

hlm = K�V 2

2(A.7)

where

{ Le=Equivalent length

{ K= Loss coe�cient

59

The friction factor for laminar ow is

flaminar =64

Re(A.8)

This friction factor does not take into account pipe roughness,and is inversely proportional to the Reynolds number. However,the friction factor for turbulent ow may be found by combining�gure A.4 and �gure A.3. This is due to the protrusion of roughsurfaces inside the pipe which penetrate through a thin viscoussub-layer of the uid on the inner wall of the pipe. This resultsin an increase in drag on the uid causing a pressure loss. Thissub-layer is represented in �gure A.2. Thus, this friction factorcaused by turbulent ow depends on the ratio e

Dwhere e is the

roughness of the pipe, and D is once again the inner diameter ofthe pipe.

The loss coe�cient k for minor losses may also be used to �nd thehead loss created in inlets, enlargements and contractions. Thesevalues for k may be determined using Tables A.1 and A.2 in �gureA.5

Equivalent length as used in the above equations may be usedto represent bends, valves and �ttings, to a more simple repre-sentation as a length of straight pipe. The head loss in thesebends, valves and �ttings is much larger than the headloss infully developed straight ow. This headloss is primarily causedby secondary ow. In short, secondary ow is any ow that doesnot follow the primary downstream owlines. This can be eas-ily seen in the spiraling motion observed in ow through a bendor through the separation e�ects ovserved in valves and �ttings.This secondary ow uses up energy that would otherwise be usedto move the uid downstream. Examples of these secondary owtypes are represented in �gure A.6.

60

Velocity profile for Laminar Flow

V

V

Ideal velocity profile for turbulent flow

Figure A.1: Velocity pro�les

61

Vinfinity

V0

Sublayer

Figure A.2: Example of the sublayer of uid located on the inner wallof a pipe

62

Friction factor

Reynolds num

ber

Relative roughness, e/D

Figu

reA.3:

Friction

factorfor

fully

develop

ed ow

inpipes(D

atafrom

Fox

andMcD

onald

)

63

Pipe diam

eter (inches)

Relative Roughness, e/D

Figu

reA.4:

Relative

roughness

forpipes

(Data

fromFox

andMcD

on-

ald)

64

Table A1

Entrance Type

Reentrant

Sharp-edge

Rounded-edge

K

0.78

0.5

r/D 0.02 0.06 >0.15K 0.28 0.15 0.04

Minor loss coefficients for pipe entrances

A2/A1 10 15-40 50-60 90 120 150 180

0.50 0.05 0.05 0.06 0.12 0.18 0.24 0.26

0.25 0.05 0.04 0.07 0.17 0.27 0.35 0.41

0.10 0.05 0.05 0.08 0.19 0.29 0.37 0.43

θ

A1 A2θ

Table A2

Minor loss coefficients for gradual contractions

Figure A.5: Minor loss coe�cients (Data from Fox and McDonald)

65

A

A Cross-sectional View A

Flow through a Bend

Flow through a Valve or Fitting

Secondary Flow

Figure A.6: Secondary ow caused by bends, valves and �ttings.

66

Appendix B

Fluid Machinery

Among various processing plants, di�erent processes and machin-ery are used depending on what liquid products the facility wishesto produce. However, one necessary piece of machinery for all ofthese plants are pumps. The purpose of this chapter is to intro-duce and analyze uid machines used in industry. The ows beingused with these pumps will all be incompressible liquid ows, andthis type of machinery is all work absorbing, in that work is putinto the system to move the uid. Later in the chapter, workproducing uid machinery will be looked at as well.

B.1 Classi�cation of Fluid Machinery

Work absorbing uid machinery may be classi�ed into two majorcategories, positive displacement or dynamic. The �rst category,positive displacement machinery, uses an energy transfer which isdone by volume changes within the inside of a closed chamber orpassage. The second classi�cation deals with devices that direct uid ow with vanes or blades which rotate on a shaft. These aremore speci�cally termed turbomachines, and they have a dynamicdisplacement of uid.

67

The di�erence between these types of machinery is that all of thework interaction in turbomachinery results from the dynamic ef-fects of the rotor on the uid stream. An example of a positivedisplacement machine commonly used in the petroleum industryis the reciprocating compressor. Compressors such as this areused for uids in gaseous phases, and these compressors are dis-cussed in the following chapter. The emphasis of this chapter willdeal with dynamic machines.

Inside the branch of turbomachinery, a further distinction can bemade into radial and axial ow machines. In radial or centrifugal ow machines, the ow path is essentially radial. This ow pathalso has a dramatic change in the radius from the inlet to theoutlet. On the other hand, axial ow machines have a ow pathwhich is more or less parallel to the centerline of the machine.

The terminology given to these machines when dealing with in-compressible uids are pumps. Similar machines which are usedto move gases and vapor are called fans, blowers, and compressors.The rotating element in a pump which drives the uid is calledthe impeller. This impeller is then contained inside a housingwhich allows the impeller to direct the ow through the pump.

Three types of these centrifugal machines are shown in �gure B.1.Flow enters each machine in an axial direction. The entrancepoint of the ow has a radius r1. Flow then exits the impellerthrough an opening of width, b, at a radius of r2.

Similar to pumps and compressors are turbines. However, theprimary di�erence between turbines and pumps is that turbinesextract energy from the uid.

A turbine assembly is composed of vanes or blades which areattached to a turbine shaft. This entire assembly is called arotor. Two types of turbines are primarily used in uid ows,these are gas or steam turbines and hydraulic turbines, where the uid mediums are gas and liquid respectively. Within this cate-gory, two typical types of turbines are used, the Francis type alsoknown as a reaction turbine and the Kaplan type also known asa propeller turbine. In the Francis type turbine shown in �gure

68

b

r2

r1

(a) Centrifugal pump (b) Centrifugal blower

(c) Centrifugal compressor

Volute

Impeller vane

Eye

Figure B.1: Schematic diagrams of typical centrifugal- ow turboma-chines.

B.2 Liquid enters the casing of the turbine where it ows cir-

69

cumferentially. This ow is then directed into the rotor by thestationary guide vanes. After driving the rotor, the liquid then ows through a di�user and �nally leaves the turbine.

Also represented in �gure B.2 is the Kaplan type propeller tur-bine. In this assembly, liquid enters the turbine in the same fash-ion as it did for the Francis type turbine. However, this liquid isdirected to ow nearly axial to the rotor shaft. This liquid thendrives the rotor as it passes through the turbine.

B.2 Turbomachinery Analysis

Depending on the information desired about the system, variousmethods of analysis can be used to analyze turbomachinery. Incases such as those used in petroleum processes, the desired infor-mation is usually ow rate, pressure change, torque and power.This information can be found by applying a �nite control vol-ume.

B.2.1 The Angular Momentum Principle

The principle of angular momentum, when applied to a controlvolume, results in the equation:

~r�~Fs+ZCV

~r � ~g�dV+~TShaft =@

@t

ZCV

~r � ~V �dV+ZCS

~r � ~V �~V �dA

(B.1)

B.2.2 Euler Turbomachine Equation

When analyzing turbomachinery, it is convenient to choose a �xedcontrol volume which encloses the rotor so that the torque maybe evaluated. To simplify the analysis, torques due to surface

70

Stationary GuideVanes Rotor Vanes

Casing

Draft Tube

Guide Vanes

RotorVanes

Casing

Reaction turbine (Francis type)

Propeller turbine (Kaplan type)

Figure B.2: Schematic diagrams of typical hydraulic turbines.

71

U1

U2 Vn1

Vn2

Vt1

Vt2

ω

V1

V2

r1

r2

Y

X

Figure B.3: Finite control volume and absolute velocity componentsfor angular momentum analysis.

force are ignored. Contributions due to body forces may be ne-glected due to symmetry. Therefore, for steady ow , equationB.1 changes to:

~TShaft =ZCV

~r � ~V �~V �dA (B.2)

by selecting a �xed control volume as seen in �gure B.3 whichencloses the rotor of a turbomachine. Fluid enters the rotor at aradial location r1, with a velocity ~V1. This uid then leaves thesystem at a radial location 2, with velocity ~V2. Thus equationB.2 becomes:

TShaft = (r2Vt2 � r1Vt1) _m (B.3)

By noting that �V � dA = _m. Equation B.3 is often called the

72

Euler Turbomachine equation, and it provides a basic relation-ship between torque and angular momentum for turbomachines.Giving TShaft > 0 for pumps and compressors and TShaft < 0 forturbines.

The mechanical power, _Wm or the rate of work done on a turbo-machine rotor is given by the dot product of the angular velocityof the rotor, ~!, and the applied torque, TShaft.

_Wm = ~! � ~TShaft (B.4)

or_Wm = !(r2Vt2 � r1Vt1) _m (B.5)

From this equation, it can be noticed that the angular momentumof the uid increases with the addition of shaft work. Therefore,for a pump, _Wm > 0 the angular momentum of the uid mustincrease. On the other hand, for a turbine, _Wm < 0 and thereforethere is a decrease in the angular momentum.

By introducing U = r!, where U is the tangential speed of therotor at radius r, then

_Wm = (U2Vt2 � U1Vt1) _m (B.6)

or by dividing this equation by _mg, a quantity with the dimen-sions of length is obtained, which is termed the head added tothe ow.

H =_Wm

_mg=

1

g(U2Vt2 � U1Vt1) _m (B.7)

From these equations, one may notice that the di�erence in theproduct rVt or UVt, between the inlet and the outlet sections isimportant in determining the torque applied to the rotor or theenergy transfer to the uid.

Applying the �rst law of thermodynamics for incompressible owacross a pump or turbine, the rate of energy added to or extractedfrom the uid stream, for an ideal case, _Wh = _m�p

�= _mgH =

73

�QgH. In this case _Wh is the hydraulic power. Neglecting frictionand ow losses, the hydraulic power is equal to the mechanicalpower. However, when friction and ow losses are included, hy-draulic and mechanical power are related using e�ciency.

For pumps, the e�ciency is de�ned as �p =_Wh_Wm. Thus,

�p =_Wh

_Wm

=�QgH

!T(B.8)

For hydraulic turbines, the e�ciency is de�ned as �t =_Wm_Wh. Thus,

�t =_Wm

_Wh

=!T

�QgH(B.9)

74

B.3 Velocity Polygon Method

The importance of having clearly de�ned components for uidvelocity is seen in the equations used in this chapter. Thus, it isoften useful to create velocity polygons for both the inlet and theoutlet ow. These velocity polygons are illustrated in �gure B.4.

In an idealized situation, ow relative to the rotor is assumed toenter and leave tangent to the pro�le of the rotor blade. Thisideal situation is often referred to as shockless entry. The bladeangles, �, are measured relative to the tangential velocity of theblade. The inlet blade angle, �1, �xes the direction of the inletvelocity relative to the design conditions of the rotor assembly.

The absolute uid velocity is the vector sum of the uid ow ve-locity relative to the blade and the tangential uid velocity at thatpoint. The angle of the absolute uid velocity, �1, is measuredfrom the normal direction, as shown in �gure B.4. The tangentialcomponent of this absolute velocity, Vt1, and the component nor-mal to the ow area, Vn1, can also be seen in �gure B.4. It shouldbe noted that the normal component of the absolute velocity, Vn,and the normal component of the velocity relative to the blade,Vrbn, have equal magnitudes.

In swirl-free conditions for the inlet ow, the absolute velocitywill be completely radial in direction. The inlet blade angle maybe speci�ed for the design ow rate and pump speed to provideshockless entry ow. Pre-swirl, which may be present in the inlet ow, or created by stator vanes, will cause the absolute inlet owdirection to stray from the radial direction.

Velocity polygons are constructed in a similar fashion at the outletsection of the rotor. The tangential velocity is U2, which is foundfrom the dimensions of the rotor and the angular velocity at whichthe rotor is running. The relative ow is then assumed to leavethe impeller tangent to the blade, as shown in �gure B.4. By usingthis idealized assumption, the direction of the relative outlet owat the design conditions can be found.

75

In the case of a centrifugal pump or a reaction turbine, illustratedin �gures B.1 and B.2 respectively, the velocity relative to theblade changes in magnitude from the inlet to the outlet. Thus, thecontinuity equation must be applied, using the impeller geometry,to determine the normal component of velocity at each section.This equation in cylindrical coordinates is:

1

r

@(r�Vr)

@r+1

r

@(�V�)

@�+1

r

@(�Vz)

@z+@�

@t= 0 (B.10)

The normal component combined with the blade angle is thensu�cient enough information to establish the velocity relative tothe blade at the impeller outlet for a radial- ow machine. Thevelocity polygon for this position can then be completed.

Once the inlet and outlet conditions are established, all of theinformation needed to calculate the ideal torque or power whichis absorbed or delivered by the rotor using equations B.2 and B.4.The results of these calculations provide the performance of aturbomachine under idealized conditions. These idealized resultsrepresent the upper limits of performance for a turbomachine.

The actual performance may be estimated using the same basicapproach, however variations in ow properties across the bladespan at the inlet and outlet sections must be accounted for. Sec-ondly, deviations between the blade angles and the ow directionsmust also be taken into account. However, the calculations forthe actual performance are beyond the scope of this document.The alternative is to measure the overall performance of a turbo-machine on a suitable test stand. This data can often times befound in the speci�cations provided by the manufacturer.

Figure B.4 represent the ow through an impeller. Assuming thatthe uid enters the impeller with a purely radial absolute velocity,swirl free conditions, then the uid entering the impeller has noangular momentum and Vt1 is zero. Thus the increase in head isgiven by:

H =U2Vt2g

(B.11)

76

Then, using the exit velocity polygon of �gure B.4

Vt2 = U2 � Vrb2 cos �2 = U2 �Vn2sin�2

cos �2 (B.12)

which reduces to:

U2 � Vn2 cot �2 (B.13)

Thus equation B.11 can be whiten as:

H =U2

2� U2Vn2 cot �2

g(B.14)

For an impeller of width w, the volume ow rate is:

Q = �D2wVn2 (B.15)

Therefore, to express the head in terms of volume ow rate, Vn2

is substituted in terms of Q. Thus

H =U2

2

g�U2 cot �2�D2wg

Q (B.16)

Equation B.16 may be represented in the form

H = C1 � C2Q (B.17)

where constants C1 and C2 are functions of the rotors geometryand speed,

C1 =U2

2

g(B.18)

and

C2 =U2 cot�2�D2wg

(B.19)

Equation B.17 predicts a linear variation of the head, H, with thevolume ow rate, Q. This may be represented in �gure B.5.

77

Constant C1 represents the ideal head developed by the pumpfor zero ow rate. The slope of the curve of head verses owrate depends on the sign and magnitude of C2. For example, asillustrated in �gure B.5, for radial outlet vanes, �2 = 90� and C2 =0, the tangential component of the absolute velocity at the outletis equal to the wheel speed and is independent of ow rate. If thevanes are forward curved, �2 > 90� and C2 < 90�. The absolute uid velocity at the outlet in this case is greater than the wheelspeed and it increases as the ow rate increases. As representedin �gure B.5, the head increases linearly with increasing ow rate.In the case of a backward curved impeller, �2 < 90� and C2 > 90�.Thus the characteristics of a radial- ow machine can be alteredby changing the angle of the rotor vanes.

B.4 Performance Characteristics

An example of the characteristic curve for a centrifugal pump areshown in �gure B.6. This curve is combined with the ideal owcurve to display the signi�cant di�erence between the ideal andactual pump performance. The reasons for the di�erence in theperformance are:

{ Recirculation of uid in the impeller occurs at very low owrates

{ As ow rate increases, friction loss and leakage loss increase.

{ \Shock loss" resulting from a mismatch between in relativespeed of the uid and impeller speed.

For this typical machine, head is a maximum at shuto� and de-creases continuously as ow rate increases. Input power is min-imum at shuto� and increases as delivery is increased. Pumpe�ciency increases with capacity until the best e�ciency point isreached. E�ciency the decreases as ow rate is increased. Thusfor minimum energy consumption, pumps must be run at the beste�ciency point.

78

Another interesting characteristic is that centrifugal pumps maybe combined in series or parallel. When combined in series, pumpsdeliver greater head to the system. Parallel pumps on the otherhand, deliver more ow.

Like pumps, turbines must also be tested in order to gain accurateknowledge of their characteristics. The procedure for testing tur-bines requires a dynamometer to absorb the turbine power outputwhile the speed and torque are measured. These test are usuallydone at constant speeds with varying loads to simulate real worldconditions.

B.5 Dimensional Analysis

The purpose of this section is to provide forms of dimensionlesscoe�cients commonly used with turbomachinery. The ow coef-�cient, �, is de�ned as the ow rate divided by the exit area andtangential speed of the rotor. Giving

� =Q

A2U2

=Vn2U2

: (B.20)

Vn2 in this equation is the velocity component perpendicular tothe exit area. Next a dimensionless head coe�cient, , may beobtained by dividing the head, H, by U2

2

g. Giving

=gH

U22: (B.21)

A dimensionless torque coe�cient, � , is then obtained by dividingthe torque, T, by �A2U2

2R2. Thus

� =T

�A2U22R2

(B.22)

where � is the density of the uid, A2 is the exit area, U2 is thetangential velocity of the rotor at the exit and R2 is the radius atthe exit.

79

Finally, the dimensionless coe�cient for power is determined, �.This is obtained by normalizing the power, _W with the angularmomentum at the exit, _mU2

2. Thus

� =_W

�QU22=

_W

�!2QR22(B.23)

When dealing with pumps, the mechanical input power is greater

than the hydraulic power, and the e�ciency is de�ned as �p =_Wh_Wm.

This may then be written as

_Wm = T! =1

�p_Wh =

�QgH

�p(B.24)

Substituting the dimensionless coe�cients �, , and � into theseequations, and analogous relation is obtained.

� =�

�p(B.25)

Similarly, for turbines, the mechanical output power is less thanthe hydraulic power, and the e�ciency is de�ned as �t = _Wm= _Wh:Thus;

_Wm = T! = �t _Wh = �t�QgH (B.26)

Once again the dimensionless coe�cients, �, , and � are introducedinto the previous equation giving

� = �t� (B.27)

The dimensionless coe�cients and the equations above using them,are the basis for scaling turbomachinery. These equations allow theuse of small scale models to be used to aid in the design of full scalemachinery. In using these equations, the ow coe�cient, �, is theindependent parameter. The coe�cients for torque, power, and headare then treated as multiple dependent parameters, and viscous e�ectsof the uid are neglected. Using these assumptions, dynamic similarity

80

is achieved when the ow coe�cients are matched for models and theactual machinery.

When scaling these machines, a useful tool is the speci�c speed. Thisis obtained by combing in the ow and head coe�cients to eliminatethe machine size. This results in

Ns =!Q

12

H34

(B.28)

Incorporating dimensionless parameters such that the head is expressedas energy per unit mass, and ! is expressed in radians per second.

Ns =!P

12

H54

(B.29)

The speci�c speed may also be represented in terms of the turboma-chine's power. Since this power is proportional to the product of thevolume ow rate and the head, the speci�c speed can be represented as

Ns =!P

12

H54

(B.30)

Speci�c speed then can be viewed as the operating speed at whichthe turbomachine produces unit volume ow rate at unit head. Thusby holding the speci�c speed constant, the operating conditions of allgeometrically similar machines under similar ow conditions can bedescribed. Thus it is possible to characterize machines by their speci�cspeed at the design point. For example, low speci�c speeds are producede�ciently by radial- ow machines. High speci�c speeds are producede�ciently by axial- ow machines. Thus for a speci�ed head, one canchoose a low speci�c speed machine or a high speci�c speed machine.

B.6 Similarity Rules

Pump manufacturers o�er a limited number of casing sizes and designs.Usually, these casings are developed from a common design and altering

81

all of the dimensions by a scale ratio. Additional characteristics mayoccur by altering the impeller size or the pump speed. In such cases,the dimensionless parameters provide a solid tool for determining thepump speci�cations which resulted in altering the pump size or speed.

Dynamic similarity between two pumps of similar design is found byholding the dimensionless ow coe�cient constant and comparing the ow rate, rotational speed and the pump diameter. It should also benoted that the ow �elds must be similar and the viscous e�ects mustbe neglected. Assuming all of this gives

Q1

!1D13=

Q2

!2D23

(B.31)

Since the dimensionless head and power coe�cients are only dependenton the ow coe�cient.

H

!2D2= f1(

Q

!D3) (B.32)

and

P

�!3D5= f2(

Q

!D3) (B.33)

Using this relationship, pump characteristics at a new condition can becompared to characteristics at an old or previous position by

H1

!12D1

2=

H2

!22D2

2(B.34)

and

P1

�1!13D1

5=

P2

�2!23D2

5(B.35)

These scaling relationships allow a prediction of the e�ects the changesin pump operating speed, size, or impeller diameter within a givenhousing have.

82

Vrb2

V2

U2

U1

V1

r2

r1

Vrb1

(a) Absolute velocity as a sumof the velocity relative to the blade

and the rotor velocity.

U1

V1

Vrb1

Vn1

Vt1

V2

U2

Vrb2 Vt2

Vn2

(b) Velocity polygon at inlet

(c) Velocity polygon at outlet

α1

α2

β1

β2

Figure B.4: Geometry and notation used to develop velocity polygonsfor a typical radial- ow machine.

83

H=ω R2

g

22

β2=90

β2<90

β2>90Forward Curve

Backward Curve

, radial

Volume flow rate, Q

Hea

d, H

Figure B.5: Idealized relationship between head and volume ow ratefor a centrifugal pump with forward-curved, radial, and backward-curved impeller blades.

84

Actual head-flowcurve Approximate

best efficiencypoint.

"Shock" loss

Loss due to recirculation

Ideal head-flow curve

Loss due to internal flowfriction

Volume flow rate, Q

Hea

d, H

Figure B.6: Comparison of ideal and actual head- ow curves.

85

86

Appendix C

Compressor Calculations

There are �ve factors which must be looked at when selecting a com-pressor. These are:

{ Cylinder Displacement

{ Volumetric E�ciency

{ Discharge Temperature

{ Adiabatic Head

{ Power

C.0.1 Cylinder Displacement

Cylinder displacement can be calculated through the use of geometricrelations of the compressor components. For a single acting cylinder:

Displacement = St � ! ��D2

4(C.1)

where:

{ X = Cylinder displacement

{ St=Piston stroke

{ ! = Strokes per minute

{ D = Piston face diameter

87

C.0.2 Volumetric E�ciency

To determine the actual inlet capacity of a cylinder, the calculateddisplacement must be modi�ed. One reason behind this modi�cationis due to the clearance between the piston and the end of the cylinderwhich is denoted in �gure C.1 by �.

δ

Inlet valve

Outlet valve

Fully Extended Fully Extracted

Figure C.1: Representation of the clearance between the cylinder walland the piston.

During the expansion portion of the cycle represented in process 3 to4 in the P-V diagram below, the gas trapped in the clearance expandsto partially �ll the cylinder. this can be represented by the followingequation which calculates theoretical volumetric e�ciency, Evt.

Evt = 1:00� (1

frp

1=k� 1)c (C.2)

where:

{ Evt = Theoretical Volumetric E�ciency

88

Volume

Pre

ssur

e

3

4 1

2

Figure C.2: P-V diagram for cylinder.

{ f =Z2

Z1= ratio of discharged compressibility to inlet com-

pressibility

{ rp = pressure ration

{ k= cpcv= isentropic exponent

{ c= compressor coe�cient

89

The inlet capacity of the cylinder is then calculated by:

Q1 = Evt �X (C.3)

C.0.3 Discharge Temperature and Adiabatic Head

The discharge temperature may be represented as:

T2T1

= rp(k�1)k (C.4)

and the adiabatic head may be calculated by:

�h = h2 � h1 = RT1k

k � 1(rp

(k�1)k � 1) (C.5)

where:

{ �h = adiabatic head

{ rp = pressure ratio

{ k = isentropic exponent

C.0.4 Power

The work-per-stage can be calculated by multiplying the adiabatic headby the mass ow per stage.

� _W = �h� _m (C.6)

� _W = _mRT1k

k � 1(rp

(k�1)k � 1) (C.7)

replacing _mRT1 with P1Q1 produces:

� _W = P1Q1

k

k � 1(rp

(k�1)k � 1) (C.8)

where:

90

{ P1 = initial pressure

{ Q1 = inlet capacity of the cylinder

The �gure C.3 gives values of e�ciency plotted against pressure ratioswhich may be used for compressor selection. Valve velocity in this �gureis taken to be 3000 fpm and the mechanical e�ciency of the system is95%.

1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.572

74

76

78

80

82

84

86

Effi

cien

cy (

%)

Pressure ratio

Figure C.3: E�ciency versus pressure ratios (data taken from Brown[?].

91

92

Bibliography

[1] Robert Fox, Introduction to Fluid Mechanics, [New York,John Wiley and Sons, INC 1992].

[2] James H. Gary, Petroleum Re�ning Technology and Eco-nomics, [New York, Marcel Dekker, 1994].

[3] D. S. J. Jones, Elements of Petroleum Processing, [New York,John Wiley and Sons, 1995].

[4] Arthur L. Kohl, Gas Puri�cation, Fourth Edition [Houston,Gulf Publishing Company, 1985].

[5] C. F. Kruse, Plant Processing of Natural Gas, [Austin,Petroleum Extension Service, 1974].

[6] Jodie Leecraft, Field handling of Natural Gas, Fourth Edition,[Austin, Petroleum Extension Service Division of ContinuingEducation, 1987].

[7] Robert A. Meyers, Handbook of Petroleum Re�ning Processes,[New York, McGraw-Hill 1996].

[8] Pierre Pichot, Compressor Application Engineering, [Houston,Gulf Publishing Company, 1986].

93