pe 505 natural gas engineering

PE505 NATURAL GAS ENGINEERING

Study Material

PE 505 NATURAL GAS ENGINEERING

ByJ.VENI

Assistant ProfessorDepartment of Petroleum Engineering

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UNIT IFormation of Crude Oil and Natural Gas

It’s derived from microscopic, photosynthetic organisms known as phytoplankton that live at or near the surface of lakes and oceans.

Associated with the phytoplankton are their microscopic predators known as zooplankton, together with land vegetation washed into lake or near shore marine sediments, accumulate over a period of millions of years.

Sediment is deposited; the organic matter is buried so that its complete destruction by bacterial activity is prevented. During burial, a number of changes (termed diagenesis) begin quickly under the influence of bacteria. The most notable process is the conversion of major biological building blocks, or biopolymers (proteins, cellulose, and lipids), into their individual components biomonomers (amino acids, sugars, and fatty acids).

These accumulate in the sediments, which, as they settle due to overburden, begin to be heated by the earth's geothermal gradient, which averages about 1.2°F per 100 feet of burial. Hence, sediment buried to 10,000 feet would have a temperature increase of 120°F over its ambient temperature at the surface.

During this process, the bio-monomers begin to react among themselves, growing into a complex two-dimensional refractory organic structure known as Kerogens.

Under further thermal stress and over millions of years of burial, slow reactions occur, removing oxygen as carbon dioxide and water and transforming the Kerogens to crude oil.

When burial is great, resulting in temperature elevations to above about 150 to 200°F, the source rock becomes over-mature and crude oil can be transformed to hydrocarbon gases.

At very high temperatures (exceeding 200°F), most of the crude oil and natural gas is converted to methane, known in the industry as dry gas. Following the formation of oil and gas, the fluids are mobilized into reservoirs.

Both time and elevated heating are thus responsible for transforming organic matter derived from decaying organisms to petroleum and gas.

The original chemistry of the organic matter, the environment of deposition, and the time and heat imposed on the organic matter dictate the type of crude oil or gas formed. The chemistry of the oil and gas can often help to reconstruct the source of the original organic matter and temperature of hydrocarbon generation.

Crude oil formed during this long and complex process is composed of a mixture of many substances, from which various refined petroleum products (such as gasoline, kerosene, fuel oil, and lubricating oil) are manufactured. These substances are mainly composed of carbon (C) and hydrogen (H), and are therefore called hydrocarbons.

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Other elements, such as oxygen (O), sulfur (S), and nitrogen (N), may also be present in relatively smaller quantities, together with traces of phosphorus (P) and heavy metals like vanadium (V) and nickel (Ni).

Inorganic Hypothesis: There are two theories of origin: Organic (bionic) or Inorganic (abionic). Early theories postulated an inorganic origin when it became apparent that there were widespread deposits of petroleum throughout the world.

Dmitri Mendeleev (1877), a Russian and the father of the periodic table of elements, reasoned that metallic carbides deep within Earth reacted with water at high temperatures to form acetylene (C2H2) which subsequently condensed to form heavier hydrocarbons. This reaction is readily reproduced in the laboratory.

Berthelot (1860) Mendeleev (1902), were a modification of the acetylene theory. They theorized that the mantle contained iron carbide which would react with percolating water to form methane: FeC2 + 2H2O = CH4 + FeO2 The problem was and still is the lack of evidence for the existence of iron carbide in the mantle. These theories are referred to as the deep-seated terrestrial hypothesis.

Sokoloff (1890) who proposed a cosmic origin. His theory was one of hydrocarbons precipitated as rain from original nebular matter from which the solar system was formed and then ejected from earth's interior onto surface rocks. This theory and others like it are referred to as the extraterrestrial hypothesis.

There are problems however, with the inorganic hypotheses. First, there is no direct evidence that will show whether the source of

the organic material in the chondritic meteorites is the result of a truly inorganic origin or was in an original parent material which was organically created. Similar reasoning applies to other celestial bodies.

Second, there is no field evidence that inorganic processes have occurred in nature, yet there is mounting evidence for an organic origin.

Third, there should be large amounts of hydrocarbons emitted from volcanoes, congealed magma, and other igneous rocks if an inorganic origin is the primary methodology for the creation of hydrocarbons.

Organic Hypothesis: Organic theory holds that the carbon and hydrogen necessary for the

formation of oil and gas were derived from early marine life forms living on the Earth during the geologic past -- primarily marine plankton. Although plankton is microscopic, the ocean contains so many of them that over 95% of living matter in the ocean are plankton.

Chemistry of the hydrocarbons found in the end product (oil, gas) differs somewhat from those we find in living things. Thus changes, transformation, take place between the deposition of the organic remains and the creation of the end product.

The basic formula for the creation of petroleum (oil, gas) is:

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Petroleum End Product = ([Raw Material + Accumulation +Transformation + Migration] + Geologic Time)

The Origin of LPG LPG processing involves separation and collection of the gas from its

petroleum base. LPG is isolated from the petrochemical mixtures in one of two ways: by

separation from natural gas or by the refining of crude oil. Both processes begin by drilling oil wells.

The gas/oil mixture is piped out of the well and into a gas trap, which separates the stream into crude oil and "wet" gas, which contains natural gasoline, LPG and natural gas.

The heavier crude oil sinks to the bottom of the trap and is then pumped into an oil storage tank for refining.

Crude oil undergoes a variety of refining processes, including catalytic cracking, crude distillation, and others. One of the refined products is LPG.

There are seven steps to the LPG supply chain: Production - The production process starts with oil and gas wells. Upstream Transportation - The mass quantities are transported by

ship, rail and pipeline. Refining & Storage - The refining of the LPG, from oil, takes place at oil

refineries. Downstream Transportation - The fully processed LPG is transported to

market by ship, rail, truck and pipeline. Bottling & Storage - The LPG is either used to fill LPG gas bottles or is

stored in bulk LPG depots. Distribution - LPG cylinder delivery trucks and bulk LPG tankers are

used to get the LPG to the end users. LPG End Users - There are many types of LPG end users including

residential, commercial, agriculture, and auto gas and petchem customers.

The "wet" gas, off the top of the gas trap, is processed to separate the gasoline (petrol) from the natural gas and LPG. The natural gas, which is mostly methane, is piped to towns and cities for distribution by gas utility companies. The petrol is shipped to service stations.

Some people still think that LPG is a by-product. This is simply not the case. It is actually an extremely versatile and valuable co-product, just like the gasoline and natural gas produced in the same process stream.

This LPG component, which is about 10% of total gas mixture, can be used as a mixture or further separated into its three primary parts: propane, butane and iso-butane. Propane (LPG in Australia) is about 5% of the total gas mixture. Best of all, it can be compressed into a liquid for transport virtually anywhere.

Condensate:Natural-gas condensate

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It is a low-density mixture of hydrocarbon liquids that are present as gaseous components in the raw natural gas produced from many natural gas fields.

It condenses out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas.

The natural gas condensate is also referred to as simply condensate, or gas condensate, or sometimes natural gasoline because it contains hydrocarbons within the gasoline boiling range.

Raw natural gas may come from any one of three types of gas wells: Crude oil wells—Raw natural gas that comes from crude oil wells is called

associated gas. This gas can exist separate from the crude oil in the underground formation, or dissolved in the crude oil.

Dry gas wells—These wells typically produce only raw natural gas that does not contain any hydrocarbon liquids. Such gas is called non-associated gas.

Condensate wells—these wells produce raw natural gas along with natural gas liquid. Such gas is also non-associated gas and often referred to as wet gas.

Introduction of Natural Gas: Natural gas is lighter than air, colorless, odorless, and tasteless. For

this reason, odorant is added to the gas to make it noticeable and objectionable for safety reasons.

Natural gas can be compressed and, therefore, transmitted in large quantities through relatively small pipe diameters when under high pressure.

Natural gas is combustible, and when burned it gives off a great deal of energy. Natural gas is clean burning and emits lower levels of potentially harmful byproducts into the air.

Natural gas is a combustible mixture of hydrocarbon gases. While natural gas is formed primarily of methane, it can also include ethane, propane, butane, and pentane.

Origin of Natural Gas: According to this theory the natural gas is formed by a chemical

reaction in the earth of the marine organisms that were buried in the sands, which was initially the seashore. The organic theory states that oil and gas have biological origins.

When the earth was mainly covered by water, small sea creatures and plants that were dead settled to the bottom of the ocean floor, over the year’s layers and layers of sand, silt and clay built up on top of them.

This decayed matter from plants and animals is called organic matter. As the years passed, these sands were further overlaid with sediments pushing the organic matter further down. The increased burden, the resulting heat, pressure made the sands and other materials transform into rock formations known as "reservoir rock".

Over time, the reservoir rock covered the organic material and trapped it beneath the rock. Through the ever increasing heat and pressure

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and the process of decay, the decayed sea creatures and plants were converted to oil and gas. Thus almost all oil and gas are derived from tiny decayed plants, algae, and bacteria.

Oil forms first, and then with the increase in the temperature and pressure at greater depth gas begins to form.

Oil and gas form as a consequence of an environmental conditions occurring in a sequence

The presence of organic material Organic remains are trapped and preserved in sediments The material is buried deeply. Then it is heated by increased

temperature and pressure. The biological stage:During the immature, or biological, stage of petroleum formation, biogenic methane (often called marsh gas) is produced as a result of the decomposition of organic material by the action of anaerobic microbes. These microorganisms cannot tolerate even traces of oxygen and are also inhibited by high concentrations of dissolved sulfate.Thermal stage:In the post mature stage, below about 5,000 meters (16,000 feet), oil is no longer stable, and the main hydrocarbon product is thermal methane gas. The thermal gas is the product of the cracking of the existing liquid hydrocarbons. These hydrocarbons with a larger chemical structure than that of methane are destroyed much more rapidly than they are formedTypes of Natural Gases:

When natural gas is used as an energy source within a home, it is almost entirely pure methane. This form of gas is considered a dry form, because all of the hydrocarbons have been removed. If the hydrocarbons are present within the gas, the gas is known as a wet form.

It is a type of petroleum that commonly occurs in association with crude oil. Natural gas is often found dissolved in oil at the high pressures existing in a reservoir, and it can be present as a gas cap above the oil. Such natural gas is known as associated gas. There are also reservoirs that contain gas and no oil. This gas is termed nonassociated gas.

Natural gas, in itself, might be considered a very uninteresting gas - it is colorless, shapeless, and odorless in its pure form. Quite uninteresting - except that natural gas is combustible, and when burned it gives off a great deal of energy.

Unlike other fossil fuels, however, natural gas is clean burning and emits lower levels of potentially harmful byproducts into the air. We require energy constantly, to heat our homes, cook our food, and generate our electricity.

It is this need for energy that has elevated natural gas to such a level of importance in our society, and in our lives. Natural gas is a combustible mixture of hydrocarbon gases.

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While natural gas is formed primarily of methane, it can also include ethane, propane, butane and pentane. The composition of natural gas can vary widely, but below is a chart outlining the typical makeup of natural gas before it is refined.

In its purest form, such as the natural gas that is delivered to your home, it is almost pure methane. Methane is a molecule made up of one carbon atom and four hydrogen atoms, and is referred to as CH4.

Chemical Name Chemical Formula Percentage (%)Methane CH4 70-90%Ethane C2H6Propane C3H8 0-20%Butane C4H10Carbon Dioxide CO2 0-8%Oxygen O2 0-0.2%Nitrogen N2 0-5%Hydrogen sulphide H2S 0-5%Rare gases Ar, He, Ne, Xe trace

Chemical Name Chemical Formula Percentage (%)Methane CH4 40-50%Ethane C2H6 5-10%Propane C3H8 1-5%Carbon Dioxide CO2 20-3-%Hydrogen sulphide H2S 0-1%

Gas Sources:The varieties of gas compositions can be broadly categorized into three distinct groups:(1) Nonassociated gas that occurs in conventional gas fields, (2) Associated gas that occurs in conventional oil fields, and (3) Continuous (or unconventional) gas.

Natural gas can be measured in a number of different ways. As a gas, it can be measured by the volume it takes up at normal temperatures and pressures, commonly expressed in cubic feet. . Production and distribution companies commonly measure natural gas in thousands of cubic feet (Mcf), millions of cubic feet (MMcf), or trillions of cubic feet (Tcf). While measuring by volume is useful, natural gas can also be measured as a source of energy. Like other forms of energy, natural gas is commonly measured and expressed in British thermal units (Btu). One Btu is the amount of natural gas that will produce enough energy to heat one pound of water by one degree at normal pressure. To give an idea, one cubic foot of natural gas contains about 1,027 Btus.

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When natural gas is delivered to a residence, it is measured by the gas utility in 'therms' for billing purposes. A therm is equivalent to 100,000 Btu's, or just over 97 cubic feet, of natural gas.

Physical Properties of Natural Gas: Natural gas is nontoxic:

Natural gas contains no toxic poisonous ingredients that can be absorbed into the blood when inhaled.

Natural gas is lighter than air:If natural gas escapes into the atmosphere, it dissipates rapidly. A heavier-than-air gas, such as propane or gasoline fumes, would settle and accumulate near the ground.

Natural gas is colorless:When mixed with the proper amount of air and ignited, invisible natural gas burns with a clean, blue flame. It is one of the cleanest burning fuels, producing primarily heat, carbon dioxide and water vapor.

Natural gas is odorless:When taken from the ground, natural gas is odorless. A harmless but pungent odor is added as a safety precaution. The odorant is so powerful you can smell even the smallest quantity of gas in the event of a leak.

Chemical Properties of Natural Gas: It is made of hydrocarbons. The main component is methane which is a very unreactive component. It has narrow combustion limits. It will ignite only when there is an air and gas mixture of between 5 and 15 percent natural gas. Ignition point : 593 degree C, Relative density : 0.3 m/s + It has a flammability range of 4.5% to 14.5%, It undergoes uninhibited chain reaction. When gas is burned completely carbon dioxide and water vapor are produced.

Application of Natural Gas: Fuel for industrial heating and desiccation process Fuel for the operation of public and industrial power stations Household fuel for cooking, heating and providing hot water Fuel for environmentally friendly liquid natural gas vehicles Raw material for chemical synthesis Raw material for large-scale fuel production using gas-to-liquid (GTL)

process (e.g. to produce sulphur-and aromatic-free diesel with low-emission combustion)

NATURAL GAS PURITY TESTSNatural gas consists of very high levels of solid and liquid contaminants as well as corrosives in varying concentrations. There are usually three popular testing procedures used to evaluate the purity and energy content of natural gas. They are as follows:

Moisture Analysis ; Sulfur Analysis, and; BTU (energy) Analysis8

http://en.wikipedia.org/wiki/Gas-to-liquid

http://en.wikipedia.org/wiki/Chemical_synthesis

http://en.wikipedia.org/wiki/Desiccation


Moisture AnalysisA variety of methods are covered under moisture analysis for measuring moisture content in both high level and trace amounts in natural gases, besides other gases, solids and liquids. Moisture analysis is important for manufacturing and process quality assurance of natural gas. Some methods used for moisture analysis are as follows:

Loss on Drying Method: This is an old laboratory method used for measuring high level moisture in natural gas. In the loss on drying (LOD) method, sample natural gas is weighed, heated in an oven for a fixed period, cooled in the dry atmosphere of a desiccators, and then weighed again. If the volatile content of the gas is mainly water, the LOD technique gives a good measure of moisture content. This technique has both the manual and automatic versions.

Karl Fischer Titration: Another method for determining moisture is the Karl Fischer titration. Developed by a German chemist by the same name, this method is useful as it detects only water, contrary to LOD, which detects any volatile substances as well.

Color Indicator Tubes: The color indicator tube is a useful device used in natural gas pipelines for a quick and rough measurement of moisture. Each tube consisting of chemicals react to a specific compound to form a color or stain when passed through the gas.

Chilled Mirrors: When natural gas flows over a chilled mirror or say a chilled surface, the moisture content in the gas will condense on it. This condensation begins at the dew point temperature. By obtaining the dew point temperature, the moisture content in the gas can be calculated.

Electrolytic Sensor: It uses two closely spaced, windings coated with a thin film of phosphorus pent oxide (P2O5). As this coating absorbs water vapor that is coming in, there is a reaction which is applied to the windings that electrolyzes the water to hydrogen and oxygen. The current consumed by the electrolysis measures the the mass of water vapor entering the sensor.

Sulfur AnalysisSulphur components in natural gas are detectable to trace levels. Analytical techniques used for sulfur analysis include Gas Chromatography, Chemiluminesence, GC/AED, GC/MS, and GC/ICP/MS. BTU (energy) Analysis This is another popular technique. The quantity of natural gas delivered is calculated by multiplying the gas volume per unit time by the heating value (BTU) per unit volume. Gas chromatography, a scientific method is used in BTU (energy) analysis. In this analysis, a gas sample is separated into its component parts for measurement.INDUSTRIAL APPLICATIONS OF GAS PLANTS:The various industries served by different gas plants (oxygen, nitrogen, hydrogen, carbon dioxide, acetylene, argon, methane etc.) are as follows: Chemical Industry

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Oxygen: In the chemical industry, oxygen is required to improve the output of a large number of petrochemical processes. Pure oxygen is used in chemical oxidation reactions like the production of ethylene dichloride (EDC), propylene oxide (PO), ethylene oxide (EO), titanium dioxide (TiO2), ferric sulfate. Oxygen is also used in de-bottlenecking of air-based processes and in the production of synthesis gas (H2/CO).

Nitrogen: Nitrogen is used for blanketing in the chemical industry. It is also used as storage for protecting raw materials or finished products in liquid form, regeneration of purification beds, preparing catalysts and transporting polymer powders. It is also used to control temperature in reactors.

Carbon dioxide: This gas is used in synthesis chemistry. It is used for controlling reactor temperatures. The gas can neutralize alkaline effluents. Carbon dioxide is also used for purifying or dying polymer, animal or vegetable fibers under supercritical conditions.

Glass, Cement and Lime industry Oxygen: Besides all oxy-combustion process, oxygen is used in the

glass melting Nitrogen: This gas is used as an inert gas. In the float glass process,

in combination with hydrogen, nitrogen creates a reductive atmosphere over the tin bath.

Hydrogen: An active gas. Used with nitrogen to form a reductive atmosphere over the tin bath in the float glass process. It is also used for heat treatment of the hollow glass and pre-forms optic fibers

Acetylene: This gas is used in automatic lubrification for glass bottle production molding

Argon: Used for the filling of double glazing enclosures which can lead to high performance thermal isolation?

Oil and Gas Industry Oxygen: To enrich air of regeneration of Fluid Cracking Catalytic units.

Oxygen is used in refinery. Nitrogen: Widely used for quality protection of products and facilities,

for example blanketing. Hydrogen: Desulfurization of fuel-oil and gasoline. · Carbon dioxide:

Carbon dioxide is the mobile phase in both extraction and chromatography applications

Acetylene: The fuel gas in atomic absorption spectrophotometry (AAS)

Argon: Used in mixtures or in pure form for industrial and hospital analyses and quality control. Argon is also used as plasma gas in inductive coupled plasma emission spectrometry and as carrier gas in gas chromatography for various detector

Nitrous oxide: This gas is used as a comburant for the flame in atomic absorption spectrophotometry. It is also used in calibration gas mixtures.

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Methane: In combination with argon, methane is used for the detector in X Ray Fluorescence as quenching gas. In combination with other hydrocarbons, methane is used as reference point for the measurement of PCI of hydrocarbons or coal.

UNIT- II - Equation of state & NG processingIdeal BehaviorAn ideal gas is an imaginary gas that satisfies the following conditions:

Negligible interactions between the molecules, Its molecules occupy no volume (negligible molecular volume), Collisions between molecules are perfectly elastic — this is, no energy

is lost after colliding.For a given mass of an ideal gas, volume is inversely proportional to pressure at constant temperature, i.e,

(at constant temperature)(1)This relationship is known as Boyle’s Law. Additionally, volume is directly proportional to temperature if pressure is kept constant, i.e.,

(at constant pressure)(2)This relationship is known as Charles’ Law. By combining both laws and recognizing “R” (the universal gas constant) as the constant of proportionality, we end up with the very familiar equation:

(3)This represents the equation of state (EOS) of an ideal gas. Numerical values of “R” depend on the system of units that is used:

The ideal gas model predicts two limiting fluid behaviors: These two behaviors are a consequence of the assumptions made in the ideal gas model.

First, that the volume of the gas becomes very large at very low pressures (i.e., as , a concept that agrees with what we know from our experience in the physical world). Second, as (the volume of matter just “vanishes” if the pressure is high enough: this concept we would not be as willing to accept).

Real GasesIn reality, no gas behaves ideally. Therefore, the ideal EOS is not useful for practical applications, although it is important as the basis of our understanding of gas behavior.

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Definition of Equation of State (EOS): Assuming an equilibrium state, the three properties needed to

completely define the state of a system are pressure (P), volume (V), and temperature (T). Hence, we should be able to formulate an equation relating these 3 variables, of the form f (P, T, V) =0.

An equation of state (EOS) is a functional relationship between state variables usually a complete set of such variables. EOS is to express functional relationships between P, T and V. It is also true that most EOS is still empirical or semi-empirical. Hence, the definition:

An Equation of State (EOS) is a semi-empirical functional relationship between pressure, volume and temperature of a pure substance. Cubic equations of state and specific high accuracy equations: Van der Waals equation of state , Redlich– Kwong equation of state Soave modification of Redlich-Kwong, Peng–Robinson equation of state

Advantages of Using Cubic Equations of State:All cubic equations of state have their foundation in VDW EOS. The use of cubic equations of state has become widespread because of their advantages:

Simplicity of application Only a few parameters need to be determined

The van der Waals equation:The contributions of VDW EOS can be summarized as follows:

It radically improved predictive capability over ideal gas EOS, It was the first to predict continuity of matter between gas and liquid, It formulated the Principle of Corresponding States (PCS), It laid foundations for modern cubic EOS. VDW proposed to semi-empirically remove the main key “weaknesses” that the ideal EOS carried with it. VDW accounted for the non-zero molecular volume and non-zero force of attraction of a real substance. He realized that there is a point at which the volume occupied by the molecules cannot be neglected. VDW recognized is that molecules must have a finite volume, and that volume must be subtracted from the volume of the container.

A= aPR2T 2 ;

B= bPRT ; Z

3−(1−B)Z2+AZ−AB=0Redlich-Kwong EOS:Redlich and Kwong EOS expression:

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,

( ) ; Soave-Redlich-Kwong EOS

,

Peng-Robinson EOS:

Where:

Gas measurement Orifice meters, Gas turbine meters, & Vortex meters, Ultrasonic

metersOrifice meter:

An orifice plate is essentially a restriction in the pipe that forces the fluid to accelerate and then decelerate as it flows through the meter. In the resulting changes in pressure as confirmed by the Bernoulli equation. Flow rate is inferred from the pressure difference by pressure taps upstream and downstream of the plate. Orifice meter is using the following topics: meter piping and differential pressure (DP) devices, meter tube and fitting, sealing units, ANSI/API

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specifications, calculation of gas flow rates, orifice meter operation, sources of error, and current research programs. Values A and B are bypass values, C the bleed valve, and D and E supply values. While fig may suggest that the matter is “clamped” to the pipe, a separate, firm, reasonably level, and vibration – free support is highly recommended. The mercury – manometer and bellows-type differential pressure (DP) measuring devices. The bellows-type is often preferred because:1. It is particularly adaptable to measuring wet gas due to its self-draining

feature.2. It finds wide applicability with integrators and controllers due to its

rapid response and high torque output.The bellows-type meter should always be mounted above the orifice to exploit its self-draining ability, unless a liquid-filled system with seal pots is used.Turbine meters:It is available for gas measurement in sizes and working pressures ranging from 0.24 to 3.36MMscfd and 175 to 1440 psig. The construction of turbine meters is presented first and then meter performance is reviewed by discussing the validity of two basic assumptions:

1. The rotor rotation varies linearly with the average fluid velocity2. The volumetric flow rate is proportional to the average fluid velocity

Gas turbine meters: The driving torque is proportional to the density of the flowing gas; this torque is much lower than for liquids. The rotor speed is therefore maintained high by operating at pipeline velocities and by having a high ratio of center body diameter to pipe diameter. A nose cone or flow deflector forces the gas to flow through an annulus having an open area approximately one-third of the open pipe area, thus providing more driving torque. The nose cone also absorbs most of the flow stream thrust that otherwise might damage the rotor bearings. The rotor spins at similar speeds to those for liquids and hence smaller blade angles are used (10°) compared to liquids (35°). The rotor blades are often helical rather than flat and are machined or molded as an integral part of the hub to improve strength. Because light weight improves rotor performance and bearing life, high strength, impact-resistant plastic or alumina is normally used. Bearings are usually of the ball race type and small relative to the meter partly to reduce frictional drag and partly due to the high rotational speed. The nose cone usually shields the bearings from liquids, dirt and grit entrained in the following gas. Bearings must be lubricated either permanently or periodically during operation. Most meters use a wick or felt to add lubricating oil, even when

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the meter is pressurized. Excess oil in the bearings flushes out any dirt and eventually evaporates into the gas stream. There are two distinct methods of measuring rotor rotation: mechanical and electro-magnetic. Mechanical designs use gear trains connected to a counter clock. There are four types of electro-magnetic sensors- induction pickup coil, reluctance pickup coil, modulated carrier pickup coil, and light emitting diode sensor.

Vortex meters: When a fluid impinges on a bluff or non-streamlined body, it splits into two paths. The resulting instability of the fluid flow field causes alternating vortices to shed from each side of the bluff body at a frequency proportional to the incident fluid velocity. This phenomenon is readily visible when a flag waves in the breeze. The flag pole serves as the bluff obstruction and generates vortices that cause the flag to wave. Such vortex shedding can produce sound as when a wire vibrates and “sings” in the wind. Vortices are formed alternatively. These so-called von Karman vortex street results in areas of alternating high and low pressure, Vortex meters usually use piezoelectric crystals that act as force –to-charge transducers to detect these pressure fluctuations.

Ultrasonic flow meters:Ultrasonic flow meters can be divided into four basic types:

Time of flight (TOF) , Doppler, Cross-correction & Swept-beamGas hydrates: IntroductionNatural gas hydrates are ice-like materials formed under low temperature and high Pressure conditions. Natural gas hydrates consist of water molecules interconnected through hydrogen bonds which create an open structural lattice that has the ability to encage smaller hydrocarbons from natural gas or liquid hydrocarbons as guest molecules.Structures and Properties• There are three known structures of gas hydrates: Structure I (sI), structure II (sII) and structure H (sH). These are distinguished by the size of the cavities and the ratio between large and small cavities. • SI and sII contain both a smaller and a larger type of cavity, but the large type cavity of sII is slightly larger than the sI one. The maximum size of guest molecules in sII is butane. • SH forms with three types of cavities, two relatively small ones and one quite large. • The symmetry of the cavities leaves an almost spherical accessible volume for the guest molecules. • The size and shape of the guest molecule determines which structure is formed due to volumetric packing considerations. • Additional characteristics are guest dipole and/or quadropole moments, such as for instance for H2S and CO2.

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• The average partial charges related to these moments may either increase the stability of the hydrate (H2S) or be a decreasing factor in thermodynamic stability (CO2). • SII forms with for instance propane and iso-butane and sH with significantly larger molecules, as for instance cyclo-hexane, neo-hexane. Both methane and carbon dioxide form sI hydrate. • SI hydrates forms with guest molecules less than 6 Å in diameter. The unit cell of sI hydrate contains 46 water molecules and consists of 2 small and six large cages. • The unit cell is the smallest symmetric unit of sI. The two smaller cavities are built by 12 pentagonal faces (512) and the larger of 12 pentagonal faces and two hexagon faces (51262). The growth of hydrate adds unit cells to a crystal.

Natural Gas Processing: Introduction:Raw natural gas after transmission through the field-gathering network must be processed before it can be moved into long-distance pipeline systems for use by consumers. The objective of gas processing is to separate

• natural gas• condensate• non-condensable• acid gases, • water

from a gas-producing well and condition these fluids for sale or disposal. The typical process operation modules are shown in Figure 1. Each module consists of a single piece or a group of equipment performing a specific function. All the modules shown will not necessarily be present in every gas plant. In some cases, little processing is needed; however, most natural gas requires processing equipment at the gas processing plant

1) To remove • Impurities, • water• excess hydrocarbon liquid

2) To control delivery pressureProcess modules

1. The first unit module is the physical separation of the distinct phases, which are typically

gas liquid hydrocarbons liquid water

solids Phase separation of the production stream is usually performed in an inlet separator. Hydrocarbon condensate recovered from natural gas may be shipped without further processing but is typically stabilized to produce a safe transportable liquid. Unstabilized condensates contain a large percentage

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of methane and ethane, which will vaporize easily in storage tanks. The next step in natural gas processing is acid gas treating. In addition to heavy hydrocarbons and water vapor, natural gas often contains other contaminants that may have to be removed. Carbon dioxide (CO2), hydrogen sulfide (H2S), and other sulfur-containing species such as mercaptans are compounds that require complete or partial removal. These compounds are collectively known as “acid gases.” H2S when combined with water forms a weak sulfuric acid, whereas CO2 and water form carbonic acid, thus the term “acid gas.” Natural gas with H2S or other sulfur compounds present is called “sour gas,” whereas gas with only CO2 is called “sweet.” Both H2S and CO2 are very undesirable, as they cause corrosion and present a major safety risk. Depending on the pressure at the plant gate, the next step in processing will either be inlet compression to an “inter stage” pressure, typically 300–400 psig or be dew point control and natural gas liquid recovery.

Scope of natural gas processingThe important factors that usually determine the extent of gas processing include the processing objectives, the type or source of the gas, and the location and size of the gas fields.Processing ObjectivesProcessing of a gas stream may have one of the following three basic objectives. • To produce a sales gas stream that meets specifications of the type. These specifications are mainly intended to meet pipeline requirements and the needs of industrial and domestic consumers• To maximize NGLs production by producing a lean gas stripped of most of the hydrocarbons other than methane• To deliver a commercial gas. Such gas must be distinguished by a certain range of gross heating value lyingPhase separationIntroduction1. Separation of oil and gas is a critical field processing operation. As producing pressure is increased and lighter condensates are produced, efficient separation has become more critical than ever. 2. Selection should be made based on the droplet size, concentration, and whether the liquid has waxing or fouling tendencies .Before evaluating specific technologies, it is important to understand the mechanisms used to remove liquids and solids from gases. Three principles used to achieve physical separation of gas and liquids or solids are momentum, gravity settling, and coalescing.1. Momentum force is utilized by changing the direction of flow and is usually employed for bulk separation of the fluid phases. 2. The gravitational force is utilized by reducing velocity so the liquid droplets can settle out in the space provided. 3. Gravity segregation is the main force that accomplishes the separation, which means the heaviest fluid settles to the bottom and the lightest fluid

17


rises to the top. However, very small droplets such as mist cannot be separated practically by gravity. These droplets can be coalesced to form larger droplets that will settle by gravity. General DescriptionAll gravity separators normally have the following components or features• A primary gas/liquid separation section with an inlet diverter to remove the bulk of the liquid from the gas.• A gravity-settling section providing adequate retention time so that proper settling may take place.• A mist extractor at the gas outlet to capture entrained droplets or those too small to settle by gravity.• Proper pressure and liquid-level controls.Gravity separators are designed as either horizontal or vertical pressure vessels.Horizontal three-phase separator

The fluid enters the separator and hits an inlet diverter. This sudden change in momentum generates the initial bulk separation of liquid and gas. In most designs, the inlet diverter contains a down comer that directs the liquid flow below the oil/water interface. This forces the inlet mixture of oil and water to mix with the water continuous phase in the bottom of the vessel and rise through the oil/water interface. This process is called “water washing” and promotes the coalescence of water droplets that are entrained in the oil continuous phase. The inlet diverter assures that little gas is carried with the liquid, and the water wash assures that the liquid does not fall on top of the gas/oil or oil/water interface, mixing the liquid retained in the vessel and making control of the oil/water interface difficult. The liquid-collecting section of the vessel provides sufficient time so that the oil and emulsion form a layer or “oil pad” at the top. The free water settles to the bottom. The produced water flows from a nozzle in the vessel located upstream of the oil weir.

“Diagram refer handbook of. Natural gas. Transmission and Processing. Saeid Mokhatab. William A. Poe. James G. Speight. Page No: 199”

An interface level controller senses the height of the oil/water interface. The controller sends a signal to the water dump valve, thus allowing the correct amount of water to leave the vessel so that the oil/water interface is maintained at the design height.

The gas flows horizontally and outs through a mist extractor (normally known as a demisting device) to a pressure control valve that maintains constant vessel pressure. The level of the gas/oil interface can vary from half the diameter to 75% of the diameter depending on the relative importance of liquid/gas separation and what purpose the separator has. Advantages

18


• Require smaller diameter for similar gas capacity as compared to vertical vessels• No counter flow • Large liquid surface area for foam dispersion generally reduces turbulence• Larger surge volume capacityDisadvantages• Only part of shell available for passage of gas• Occupies more space unless “stack” mounted• Liquid level control is more critical• More difficult to clean produced sand, mud, wax, paraffin, etcCondensate stabilizationThe process of increasing the amount of intermediates (C3 to C5) and heavy (C+6) components in the condensate is called “condensate stabilization.” The scope of this process is to separate the very light hydrocarbon gases, methane and ethane in particular, from the heavier hydrocarbon components (C+3).Stabilization processesStabilization of condensate streams can be accomplished through either flash vaporization or fractionation.Stabilization by FractionationStabilization by fractionation is a detailed process, very popular in the industry and precise enough to produce liquids of suitable vapor pressureProcess Description

The liquid hydrocarbon (condensate) is brought into the system from the inlet separator and preheated in the stabilizer feed/bottoms exchanger before entering the stabilizer feed drum. Liquid from the feed drum is fed to the stabilization tower at approximately 50 to 200 psi depending on whether they are sour.

“Diagram refer handbook of. Natural gas Transmission and Processing. Saeid Mokhatab. William A. Poe. James G. Speight. Page No:250”

The condensate stabilizer reduces vapor pressure of the condensate by removing the lighter components. The stabilization is typically carried out in a reboiled absorber, with tray type internals. If a better separation is required, typically the column is changed from a top feed re-boiled absorber to a re-fluxed distillation tower. As the liquid falls into the column, it becomes leaner in light ends and richer in heavy ends. At the bottom of the tower some of the liquid is circulated through a reboiler to add heat to the tower. As the gas goes up from tray to tray, more and more of the heavy ends get stripped out of the gas at each tray and the gas becomes richer in the light ends and leaner in the heavy ends. Overhead gas from the stabilizer, which would seldom meet market specifications for the natural gas market, is then sent to the low-pressure

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fuel gas system through a back-pressure control valve that maintains the tower pressure to set point. Liquids leaving the bottom of the tower have undergone a series of stage flashes at ever-increasing temperatures, driving off the light components, which exit the top of the tower. These liquids must be cooled to a sufficiently low temperature to keep vapors from flashing to atmosphere in the condensate storage tank.

Acid gas Treating:Natural gas contains large amounts of acid gases, such as hydrogen sulfide and carbon dioxide. Natural gas containing hydrogen sulfide or carbon dioxide is referred to as sour, and natural gas free from hydrogen sulfide is referred to as sweet. There are many variables in treating natural gas. Several factors must be considered: (1) Types and concentrations of contaminants in the gas(2) The degree of contaminant removal desired(3) The selectivity of acid gas removal required(4) The temperature, pressure, volume, and composition of the gas to be processed(5) The carbon dioxide–hydrogen sulfide ratio in the gas(6) The desirability of sulfur recovery due to process economics or environmental issues. Acid gas removal processes:Natural Gas SweeteningHydrogen sulfide, carbon dioxide, mercaptans, and other contaminants are often found in natural gas streams. Gas sweetening processes remove these contaminants so that the gas is marketable and suitable for transportation. The removal of H2S from natural gas is accompanied by the removal of CO2 and COS if present, since these have similar acid characteristics.Desulfurization processes are primarily of two types:

• Adsorption on a solid (dry process)• Absorption into a liquid (wet process)

Both the adsorption and absorption processes may be of the physical or chemical type.Acid gas removal processesProcess Description

The general process flow diagram for an amine-sweetening plant varies little, regardless of the aqueous amine solution used as the sweetening agent. The sour gas containing H2S and/or CO2 will nearly always enter the plant through an inlet separator (scrubber) to remove any free liquids and/or entrained solids. The sour gas then enters the bottom of the absorber column and flows upward through the absorber in intimate countercurrent contact with the

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aqueous amine solution, where the amine absorbs acid gas constituents from the gas stream. Sweetened gas leaving the top of the absorber passes through an outlet separator and then flows to a dehydration unit (and compression unit, if necessary) before being considered ready for sale. In many units the rich amine solution is sent from the bottom of the absorber to a flash tank to recover hydrocarbons that may have dissolved or condensed in the amine solution in the absorber. The rich solvent is then preheated before entering the top of the stripper column. The amine–amine heat exchanger serves as a heat conservation device and lowers total heat requirements for the process. A part of the absorbed acid gases will be flashed from the heated rich solution on the top tray of the stripper. The remainder of the rich solution flows downward through the stripper in countercurrent contact with vapor generated in the reboiler The reboiler vapor (primarily steam) strips the acid gases from the rich solution. The acid gases and the steam leave the top of the stripper and pass overhead through a condenser, where the major portion of the steam is condensed and cooled. The acid gases are separated in the separator and sent to the flare or to processing. The condensed steam is returned to the top of the stripper as reflux. The lean amine solution from the bottom of the stripper column is pumped through an amine–amine heat exchanger and then through a cooler before being introduced to the top of the absorber column. The amine cooler serves to lower the lean amine temperature to the 100◦F range. Higher temperatures of the lean amine solution will result in excessive amine losses through vaporization and also lower acid gas-carrying capacity in the solution because of temperature effects. Particulates formed in the plant as well as those transported into the

plant can be very bothersome. A filtration scheme of mechanical and activated carbon filters is therefore important in maintaining good solution control.

Mechanical filters such as cartridge filters or precoat filters remove particulate material while carbon filters remove chemical contaminants such as entrained hydrocarbons and surface-active compounds.

“Diagram refer handbook of. Natural gas Transmission and Processing. Saeid Mokhatab. William A. Poe. James G. Speight. Page No: 274”

Natural Gas Dehydration:Natural, associated, or tail gas usually contains water, in liquid and/or vapor form, at source and/or as a result of sweetening with an aqueous solution. The major reasons for removing the water from natural gas are as follow.1. Natural gas in the right conditions can combine with liquid or free water to form solid hydrates that can plug valves fittings or even pipelines.

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2. Water can condense in the pipeline, causing slug flow and possible erosion and corrosion.3. Water vapor increases the volume and decreases the heating value of the gas.Multistage separators can also be deployed to ensure the reduction of free water that may be present. However, removal of the water vapor that exists in solution in natural gas requires a more complex treatment. This treatment consists of “dehydrating” the natural gas, which is accomplished by lowering the dew point temperature of the gas at which water vapor will condense from the gas.

“ Diagram refer from “There are several methods of dehydrating natural gas.

Liquid desiccant (glycol) dehydration Solid desiccant dehydration Refrigeration (i.e., cooling the gas)

The first two methods utilize mass transfer of the water molecule into a liquid solvent (glycol solution) or a crystalline structure (dry desiccant). The third method employs cooling to condense the water molecule to the liquid phase with the subsequent injection of inhibitor to prevent hydrate formation. However, the choice of dehydration method is usually between glycol and solid desiccants. Several other dehydration technologies (i.e., membranes, vortex tube, and supersonic processes) The commonly available glycols and their uses are described as follows:1. Mono ethylene glycol (MEG); high vapor equilibrium with gas so tend to lose to gas phase in contactor. Use as hydrate inhibitor where it can be recovered from gas by separation at temperatures below 50◦F.2. Di ethylene glycol (DEG); high vapor pressure leads to high losses in contactor. Low decomposition temperature requires low re-concentrator temperature (315 to 340◦F) and thus cannot get pure enough for most applications.3. Tri ethylene glycol (TEG); most common. Re-concentrate at 340–400◦F, for high purity. At contactor temperatures in excess of 120◦F, there is a tendency to high vapor losses. Dewpoint depressions up to 150◦F are possible with stripping gas.4. Tetra ethylene glycol (TREG); more expensive than TEG but less loss at high gas contact temperatures. Re-concentrate at 400 to 430◦F.Absorption (glycol dehydration process)The basic principles of relevance to the absorption process are as follows:1. In this process, a hygroscopic liquid is used to contact the wet gas to remove water vapor from it. Tri ethylene glycol (TEG) is the most common solvent used. 2. Absorption, which is defined as the transfer of a component from the gas phase to the liquid phase, is more favorable at a lower temperature and higher pressure.

3. The actual absorption process of water vapor from the gas phase using 22


glycol is dynamic and continuous. Therefore, the gas flow cannot be stopped to let a vapor and the liquid reach an equilibrium condition. Accordingly, the system under consideration must be designed to allow for a close approach to equilibrium while the flow continues.

Selection of glycol:TEG is better than MEG, DEG, and TREG. Because,

Easily regenerated , Low vaporization losses & Low capital cost“Diagram refer from”

“Diagram refer handbook of. Natural gas Transmission and Processing Saeid Mokhatab. William A. Poe. James G. Speight. Page No: 329”Process description:Generally, in the glycol dehydration process, TEG is pumped to the top of a dehydration unit or contactor tower where it is flow countercurrent with wet gas flowing up the tower.

The TEG adsorbs water from the wet gas and is passed to the glycol regeneration unit where, very simply, adsorbed gases are flashed off and the water is removed from the reboiler by heating the wet glycol to around 400ºF at atmospheric conditions gas. The processes are continuous, that is glycol flow continuously through dehydration unit where they come in contact and the glycol absorbs the water. The regenerated TEG is then pumped back to the dehydration unit inlet.

Gas Gathering:Gas Gathering systems are the physical facilities that accumulate and transport natural gas from a well to an acceptance point of a transportation pipeline are called a gas gathering system.

Gas Gathering lines are small-diameter pipelines move natural gas from the wellhead to the natural gas processing plant or to an interconnection with a larger mainline pipeline.

Transporting natural gas from the wellhead to the final customer involves several physical transfers of custody and multiple processing steps. A natural gas pipeline system begins at the natural gas producing well or field.

Once the gas leaves the producing well, a gas gathering system directs the flow either to a natural gas processing plant or directly to the mainline transmission grid, depending upon the initial quality of the wellhead product.

The processing plant produces pipeline-quality natural gas. This gas is then transported by pipeline to consumers or is put into underground storage for future use. Storage helps to maintain pipeline system operational integrity and/or to meet customer requirements during peak-usage periods.

NGL’S

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Natural gas is processed to remove the heavier hydrocarbon liquids from the natural gas stream. These heavier hydrocarbon liquids, commonly referred to as natural gas liquids (NGLs), include ethane, propane, butanes, and natural gasoline (condensate). Recovery of NGL components in gas not only may be required for hydrocarbon dew point control in a natural gas stream (to avoid the unsafe formation of a liquid phase during transport), but also yields a source of revenue, as NGLs normally have significantly greater value as separate marketable products than as part of the natural gas stream. Lighter NGL fractions, such as ethane, propane, and butanes, can be sold as fuel or feedstock to refineries and petrochemical plants, while the heavier portion can be used as gasoline-blending stock. NGL RECOVERY PROCESSES

1. Refrigeration processes Mechanical refrigeration Self Refrigeration Cryogenic Refrigeration

2. Lean Oil Absorption3. Solid Bed Adsorption4. Membrane Separation Process5. Selection of NGL Recovery Processes6. NGL fractionation

NGL’s recovery processes• Refrigeration process

Mechanical refrigeration Self refrigeration Cryogenic refrigeration

• Lean oil absorption• Solid bed adsorption • Membrane separation process• NGL fractionation

Fractionators Operation The operation takes place in a vertical column where vapor and liquid mixtures flow countercurrent and are brought into repeated contact. During each contact, part of the liquid vaporizes and part of the vapor condenses. As the vapor rises through the column, it becomes enriched in the lighter or lower boiling components. Conversely, the downward flowing liquid becomes richer in heavier, higher boiling components. Figure 2 is a schematic view of a typical fractionating column. The liquid mixture that is to be processed is known as the feed, which is introduced usually somewhere near the middle of the column to a tray known as the feed tray. The feed tray divides the column into a top (enriching or rectification) section and a bottom (stripping) section. The feed flows down the column where it is collected at the bottom in the reboiler. Heat is supplied to the reboiler to generate vapor. The vapor

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raised in the reboiler is reintroduced into the unit at the bottom of the column. The liquid removed from the reboiler is known as the bottoms product or, simply, bottoms. The vapor moves up the column, and as it exits the top of the unit, it is cooled by a condenser.

“Diagram refer handbook of. Natural gas. Transmission and Processing Saeid Mokhatab. William A. Poe. James G. Speight. Page No:384”

The condensed liquid is stored in a holding vessel known as the reflux drum (accumulator). Some of this liquid is recycled back to the top of the column and this is called the reflux. The condensed liquid that is removed from the system is known as the distillate or overhead product.

UNIT-III - Gas Compression& Equation of flowIntroduction“Compression” is used in all aspects of the natural gas industry, including gas lift, reinjection of gas for pressure maintenance, gas gathering, gas processing operations (circulation of gas through the process or system),

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transmission and distribution systems, and reducing the gas volume for shipment by tankers or for storage.The benefits of operating at higher pressures include the ability to transmit larger volumes of gas through a given size of pipeline, lower transmission losses due to friction, and the capability to transmit gas over long distances without additional boosting stations.In gas transmission, two basic types of compressors are used: reciprocating and centrifugal compressors. Reciprocating compressors are usually driven by either electric motors or gas engines, whereas centrifugal compressors use gas turbines or electric motors as drivers. Reciprocating compressor:

A reciprocating compressor is a positive displacement machine in which the compressing and displacing element is a piston moving linearly within a cylinder. The reciprocating compressor uses automatic spring-loaded valves that open when the proper differential pressure exists across the valve.

Reciprocating compressors are widely utilized in the gas processing industries because they are flexible in throughput and discharge pressure range.

Reciprocating compressors are classified as either “high speed” or “slow speed.” Typically, high-speed compressors operate at speeds of 900 to 1200 rpm and slow-speed units at speeds of 200 to 600 rpm.

Centrifugal compressors: Centrifugal compressors are used in a wide variety of applications in

chemical plants, refineries, onshore and offshore gas lift and gas injection applications, gas gathering, and in the transmission of natural gas.

Centrifugal compressors can be used for outlet pressures as high as 10,000 psia, thus overlapping with reciprocating compressors over a portion of the flow rate/pressure domain. Centrifugal compressors are usually either turbine or electric motor driven.

Typical operating speeds for centrifugal compressors in gas transmission applications are about 14,000 rpm for 5000-hp units and 8000 rpm for 20,000-hp units.

The rotor, or impeller, in the centrifugal compressor spins at a high speed (3,000-20,000 RPM) inside the compressor housing. The refrigerant is fed into the housing at the center of the impeller. The impeller forces the vapor against its outer diameter, by centrifugal force, causing it to move at a high speed.

The high velocity gas is then allowed to slow down and expand in a diffuser section which causes the gas pressure to increase. One process like this is called a stage of compression. A centrifugal compressor using one impeller is called a single stage machine; one which uses two impellers is called a double stage machine; etc.

When more than one stage is used, the discharge from the diffuser section of one stage goes into the inlet of the next stage. Industrial

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http://www.refrigers.com/content/view/31466/28/

http://www.refrigers.com/content/view/31449/28/


refrigeration models may make use of as many as four stages to achieve the desired compression. Air conditioning models usually have one or two stages of compression.

Compressor selectionThe design for choosing a compressor should include the following considerations.• Good efficiency over a wide range of operating conditions• Maximum flexibility of configuration• Low maintenance cost, • Low life cycle cost , • Acceptable capital cost & • High availabilityIn fact, compressor selection consists of the purchaser defining the operating parameters for which the machine will be designed. The “process design parameters” that specify a selection are as follows:1. Flow rat, 2. Gas composition 3. Inlet pressure and temperature 4. Outlet pressure5. Train arrangement

i). for centrifugal compressors: series, parallel, multiple bodies, multiple sections, intercooling, etc.ii). for reciprocating compressors: number of cylinders, cooling, and

flow control strategy6. Number of unitsCOMPRESSION DESIGNCompressor design involves several steps. These include selection of the correct type of compressor, as well as the number of stages required.In addition, depending on the capacity, there is also a need to determine the horsepower requirement for the compression.Design procedure:The capacity of the cylinder is a function of piston displacement and volumetric efficiency. This is in turn a function of cylinder clearance, compression ratio, and gas properties.Piston displacement:The actual volume of the cylinder that is swept by the piston per minute is piston displacement. It can be calculated from:Single acting cylinder (head end displacement)

PD = =(2 (dc2−d

r2 )SN2200 )

Single acting cylinder (crank end displacement)

PD =( (dc2−dr2)SN

2200 )PD- displacement, cfmS – Stroke length, inchrpm – compressor speed, rpm

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dc – diameter of cylinder, inchdr – diameter of rod, inchDouble acting cylinder (sum of head end and crank end displacement)

PD =( (2dc2−d

r2 )SN2200 )

Volumetric efficiency:

Ev = 96−R−C [ (R1/K ) Zs

Zd−1]

Ev - Stage volumetric efficiency, %R - Compression ratio (Pd / Ps) of the compressor stage (based on absolute pressure)C - Cylinder clearance, percent of piston displacementZs - compressibility factor at suction, psiaZd - compressibility factor at discharge, psiaK - ratio of specific heats, Cp / CvCylinder throughput capacity: qa = Ev ×PDqa – gas throughput at suction conditions of temperature and pressure , ft3/min

Ev -volumetric efficiency PD- piston displacement, ft3/min

qg = 35 .4

qsP s

T sZ s

qg - Gas throughput at standard conditions, scfmPs - Suction pressure, psiaTs - Suction temperature, RZs - Compressibility at suction conditions

Qg =0. 051

qaPs

T s ZsQg - Gas throughput, MMscfd

Rod load:Single acting cylinder, head end

RLc= ap (Pd – Pu) + arPu ; RLu= ap (Pu– Ps) - arPu

Single acting cylinder,crank end RLc= ap (Pu – Ps) + arPs ; RLt= ap (Pd– Pu) - arPd

Double acting cylinder RLc= ap (Pd – Ps) + arPs ; RLt= ap (Pd– Ps) - arPdRod load in compression, lbRod load in tension, lb

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Cross sectional area of piston, inch2

Discharge pressure, psiaSuction pressure, psiaPressure in unloaded area, psiaCross – sectional area of rod, inch2

Clearance:It is normally expressed as a percent or fraction of cylinder displacement.Single acting cylinder (head end clearance)

%C = CHEdc2(0 .76854 )S

¿100

Double acting cylinder (average clearance)

%C = (CHE )+(CCE )

[ dc2

(dc2−d

r2 )]( 0. 7854 )S¿100

%C – cylinder clearance, fractiondc – cylinder diameter, inchdr – rod diameter, inchCHE – head end clearance, inch3

CCE – crank end clearance, inch3S – Stroke length, inchBrake Horse Power:

BHP =0.0857 zavg((QgT s /ηE )( K

K−1 ))( P s

Pd )(k−1k )

BHP - Brake horse power per stageZavg -Average compressibility factorQg -Standard Volumetric flow rate of gas, MMscfdTs -Saturation temperature, ºRPs, Pd -Suction and discharge pressure, psiaE - Parasitic efficiency (for high speed reciprocating units 0.72 to 0.82; low speed reciprocating units 0.72 to 0.85; for centrifugal unit 0.99)ή- Compression efficiency (for reciprocating and 0.80 to 0.87 for centrifugal units)Fundamental equationsFlow of fluid derived from three fundamental laws of physics:

1. Conservation of matter , Conservation of energy & Conservation of momentum

Conservation of matter:“Matter can’t be created nor destroyed, but it may be converted” (e.g. by a chemical process)

Conservation of energy:

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“Energy can’t be created nor destroyed, but may be converted from one type to another “(e.g. potential may be converted to kinetic energy).Conservation of momentum:

“A moving body can’t gain or lose momentum unless acted upon by an external force”This is a statement of Newton’s second law of motion:Force = rate of change of momentumThe continuity equationFor any control volume during the small time interval δt the principle of conversation of mass implies that the mass of flow entering the control volume minus the mass of flow leaving the control volume equals the change of mass within the control volume.If the flow is steady and the fluid incompressible the mass entering is equal to the mass leaving, so there is no change of mass within the control volume.So for the time interval δt:Mass flow entering = mass flow leavingConsidering the control volume above which is a short length of open channel of arbitrary cross section then, if ρ is the fluid density and Q is the volume flow rate then mass flow rate is ρQ and the continuity equation for steady incompressible flow can be writtenρQentering=ρQleavingAs Q, the volume flow rate is the product of the area and the mean velocity then at the upstream face where the mean velocity is υ1 and the cross- sectional area is A1 then:Qentering = υ1A1Similarly at the downstream face, face 2, where mean velocity isυ2 and cross- sectional area A2 then: Qleaving = υ2A2

Therefore the continuity equation can be written as V 1 A1=V 2 A2

The energy equationConsider the forms of energy available for the above control volume. If the fluid moves from the upstream face 1, to the downstream face 2 in time δt over the length L.The work done in moving the fluid through face 1 during this time isWork done = P1A1LWhere P1is pressure at face 1The mass entering through face 1 is Mass entering = ρ1A1LTherefore kinetic energy of the system is: KE = ½ mu2 = ½ ρ1A1Lu12

If z1 is the height of the centroid of face 1, then the potential energy of the fluid entering the control volume is: PE = mgz = ρ1A1Lgz1The total energy entering the control volume is the sum of the work done, the potential and the kinetic energy:Total energy = ρ1A1L + ½ ρ1A1Lu12+ ρ1A1Lgz1

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In terms of energy per unit weight, as the weight of water entering the control volume is ρ1A1LgThen divide by this to get the total energy per unit weight:Total energy per unit weight = ( P1/ρ1g) + (u12/2g) +z1At the exit to the control volume, face 2, similar considerations deduceTotal energy per unit weight = ( P2/ρ2g) + (u22/2g) +z2If no energy is supplied to the control volume from between the inlet and the outlet then energy leaving = energy entering and if the fluid is incompressible ρ1= ρ2 = ρ ; ( P1/ρ1z1) + (u12/2g) +z1= ( P2/ρ2z2 ) + (u22/2g) +z2= H = constantThis is the Bernoulli equation.

1. In the derivation of the Bernoulli equation it was assumed that no energy is lost in the control volume- i.e. the fluid is frictionless. To apply to non frictionless situations some energy loss term must be included.

2. The dimensionless of each term in Bernoulli equation has the dimensions of length. For this reason each term is often regarded as a “ head” and given the names

P/ρg= pressure head ; u22/2g = velocity head; z2= potential headThe momentum equationAgain consider the control volume above during the time δtMomentum entering = ρδQ1δt u1 ; Momentum leaving = ρδQ2δt u2By the continuity principle: δQ1= δQ2And by Newton’s second law Force = rate of change of momentumδF= (momentum leaving – momentum entering) / δt = ρδQ( u2-u1)It’s more convenient to write the force on a control volume in each of the three, x, y and z direction e.g. in the x- directionδFx = ρδQ ( u2x-u1x)Integration over a volume gives the total force in the x- direction asFx = ρQ ( V2x-V1x) As long as velocity V is uniform over the whole cross – section.This is the momentum equation for steady flow for a region of uniform velocity.

UNIT – IV - Phase behavior & Gas reservoir performanceWhy Study Phase Behavior?

Natural gas and crude oil are naturally occurring hydrocarbon mixtures that are found underground and at elevated conditions of pressure and temperature. They are generally referred to as petroleum fluids. Petroleum fluids are principally made up of hydrocarbons; but few non-hydrocarbon components may be present such as nitrogen, carbon dioxide and hydrogen sulfide.

Phase Behavior has many implications in natural gas and petroleum engineering. Pressure, volume, temperature (PVT) relations are required in simulating reservoirs, evaluating reserves, forecasting

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production, designing production facilities and designing gathering and transportation systems.

Every hydrocarbon molecule in the reservoir is to embark on a fascinating journey from beneath the earth, passing through a great deal of intermediate stages, to be finally dumped into our atmosphere upon combustion (release of energy).

Phase Behavior is the part of thermodynamics that gives us the tools for the complete understanding of how fluids behave at any of those stages.

Phase Diagram: A phase diagram is a concise graphical method of representing phase behavior of fluids. It provides an effective tool for communicating a large amount of information about how fluids behave at different conditions.Definition of Basic TermsVapor Pressure: The vapor pressure of liquid is defined as the absolute pressure at which liquid and its vapor are in equilibrium at a given temperature.Dew Point: is the temperature at which vapor mixture on cooling first begins to condense.Bubble Point: is the temperature at which the liquid mixture starts to vaporize as the temperature is increased.NOTE: For single-component systems, one single curve represents all three of these conditions (vapor pressure, dew point and bubble point conditions) simply because Vapor Pressure = Dew Point = Bubble Point for unary systems.Basic phase behavior

A “phase” is defined as any homogeneous part of a system that is physically distinct and separated from other parts of the system by definite boundaries.

For example, ice, liquid water, and water vapor constitute three separate phases of the pure substance H2O because each is homogeneous and physically distinct from the others.

Moreover, each is clearly defined by the boundaries existing between them. Whether a substance exists in a solid, liquid, or gas phase is determined by the temperature and pressure acting on the substance. It is known that ice (solid phase) can be changed to water (liquid phase) by increasing its temperature and, by further increasing temperature, water changes to steam (vapor phase).

This change in phases is termed Phase Behavior. Hydrocarbon systems found in petroleum reservoirs are known to display multi-phase behavior over wide ranges of pressures and temperatures. The most important phases which occur in petroleum reservoirs are;

Liquid phase, e.g., crude oils or condensates. Gas phase, e.g., natural gases.

The conditions under which these phases exist are a matter of considerable practical importance. The experimental or the

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mathematical determinations of these conditions are conveniently expressed in different types of diagrams, commonly called Phase Diagrams.

The objective is to review the basic principles of hydrocarbon phase behavior and illustrate the use of phase diagrams in describing and characterizing the volumetric behavior of single-component, two-component, and multi-component systems.

Types of phase diagram:Single-component systems

Step 1: the pressure is increased isothermally, consequently, the gas volume decreases until it reaches point F on the diagram, where the gas begins to condense. The corresponding pressure is known as the dew-point pressure Pd, and is defined as the pressure at which the first drop let of liquid is formed.Step 2: further more liquid condenses. This condensation process is characterized by a constant pressure and represented by the horizontal line FG. At point G, traces of gas remain and the corresponding pressure is called the bubble-point pressure Pb, and defined as the pressure at which the first sign of gas formation is detected.A characteristic of a single-component system is that at a given temperature, the dew-point pressure and the bubble-point pressure are equal.Step 3: As the piston is forced slightly into the cylinder, a sharp increase in the pressure (point H) is noted without an appreciate decrease in the liquid volume. That behavior evidently reflects the low compressibility of the liquid phase.

By repeating the above steps at progressively increasing temperature, a family of curves of equal temperatures, a family of curves of equal temperature (isotherms) is constructed.

The dashed curve connecting the dew points is called the dew-point curve (line FC) and represents the states of the “saturated gas.”

The dashed curve connecting the bubble points is called the bubble-point curve (line GC) and similarly represents the “saturated liquid.” These two curves meet at point C which is known as the critical point. The corresponding pressure and volume are called the critical pressure Pc and critical volume Vc, respectively.

Two-component systems Consider that the initial pressure p1 exerted on the system, at a fixed temperature of T1, is low enough that the entire system exists in the vapor state. As the pressure is increased isothermally, it reaches point 2, at which an infinitesimal amount of liquid is condensed. The pressure at this point is called the dew-point pressure pd of the mixture. It should be noted that at the dew-point pressure, the composition of the vapor phase is equal to the overall composition of the binary mixture.

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As the volume is decreased, a noticeable increase in the pressure is observed as more and more liquid is condensed. This condensation process is continued until the pressure reaches point 3, at which traces of gas remain. At point 3, the corresponding pressure is called the bubble-point pressure pb. Because at the bubble point the gas phase is only of infinitesimal volume, the composition of the liquid phase is therefore identical with that of the whole system. Further, the pressure rises steeply to point 4 with a corresponding decreasing volume.

The phase ruleIt is appropriate at this stage to introduce and define the concept of

the “Phase Rule.” Gibbs derived a simple relationship between the number of phases in equilibrium, the number of components, and the number of independent variables that must be specified to describe the state of the system completely.

Gibbs proposed the following fundamental statement of the phase rule.F = C – P + 2

Where F = number of variables required to determine the state of the system at equilibrium, or

Number of degree of freedomC = number of independent componentsP = number of phases

A phase has been defined previously as a homogeneous system of uniform physical and chemical composition. In a system containing ice, liquid water, and water vapor in equilibrium there are three phases, i.e., P = 3.

The number of independent components in the system is one, i.e., C = 1, since the system contains only H2O. The degrees of freedom F for a system include the temperature, the pressure, and the composition (concentration) of phases. These independent variables must be specified to define the system completely.

Multi-component systems The phase behavior of multi-component hydrocarbon systems in the liquid-vapor region is very similar to that of binary systems. However, as the system becomes more complex with a greater number of different components, the pressure and temperature ranges in which to phase exist increase significantly.These multi-component p-T diagrams are essentially used to

Classify reservoirs Classify the naturally occurring hydrocarbon systems Describe the phase behavior of the reservoir fluidTo fully understand the significance of the p-T diagrams, it is necessary to identify and define the following key points on the p-T diagram: Cricondentherm (Tct) – The Cricondentherm is defined as the maximum

temperature above which liquid cannot be formed regardless of

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pressure (point E). The corresponding pressure is termed the cricondenthern pressure Pct.

Critical point - The critical point for a multi-component mixture is referred to as the state of pressure and temperature at which all intensive properties of the gas and liquid phases are equal (point C). at the critical point, the corresponding pressure and temperature are called the critical pressure pc and critical temperature Tc of the mixture.

Phase envelope (two-phase region) - the region enclosed by the bubble-point curve and the dew-point curve (line BCA), wherein gas and liquid coexist in equilibrium, is defined as the phase envelope of the hydrocarbon system.

Quality lines-The dashed lines within the phase diagram are called quality lines. They describe the pressure and temperature conditions for equal volumes of liquids. Note that the quality lines converge at the critical point (point C).

Bubble-point curve – The bubble-point curve (line BC) is defined as the line separating the liquid phase region from the two-phase region.

Dew-point curve - The dew-point curve (line AC) is defined as the line separating the vapor phase region from the two-phase region.

“Diagram refer Reservoir Engineering Hand Book – Tarek Ahmed” Page No: 2

Classification of reservoirs and reservoir fluidsProper classification of a reservoir requires the knowledge of the thermodynamic behavior of the phases present in the reservoir and forces responsible for the production mechanism. In general, reservoirs are conveniently classified on the basis of the location of the point representing the initial reservoir pressure pi and temperature T with respect to the p-T diagram of the reservoir fluid. Accordingly, reservoirs can be classified into essentially two types. These are:

Oil reservoirs - If the reservoir temperature T is less than the critical temperature Tc of the reservoir fluid, the reservoir is classified as an oil reservoir.

Gas reservoirs – If the reservoir temperature is greater than the critical temperature of the hydrocarbon fluid, the reservoir is considered a gas reservoir.

Oil reservoirsDepending upon initial reservoir pressure pi, oil reservoirs can be sub classified into the following categories:

1. Under saturated Oil Reservoir. If the initial reservoir pressure pi), is greater than the bubble-point pressure pb of the reservoir fluid, the reservoir is labeled an under saturated oil reservoir.

2. Saturated Oil Reservoir: When the initial reservoir pressure is equal to the bubble-point pressure of the reservoir fluid by point 2, the reservoir is called a saturated oil reservoir.

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3. Gas-cap Reservoir. If the initial reservoir pressure is below the bubble-point pressure of the reservoir fluid, the reservoir is termed a gas-cap on two-phase reservoir, in which the gas or vapor phase is underlain by an oil phase. The ratio of the gas-cap volume to reservoir oil volume is given by the appropriate quality line.

Gas reservoirsIn general, if the reservoir temperature is above the critical temperature of the hydrocarbon system, the reservoir is classified as a natural gas reservoir. Natural gases can be categorized on the basis of their phase diagram and the prevailing reservoir condition into four categories.

Retrograde gas-condensate, Near-critical gas-condensate Wet gas, Dry gas

Retrograde Gas-condensate Reservoir If the reservoir temperature T lies between the critical temperature Tc

and cricondentherm Tct of the reservoir fluid, the reservoir is classified as a retrograde gas-condensate reservoir.

Gas reservoir is a unique type of hydrocarbon accumulation in that the special thermodynamic behavior of the reservoir fluid is the controlling factor in the development and the depletion process of the reservoir.

Reservoir pressure is above the upper dew-point pressure, the hydrocarbon system exists as a single phase (i.e., vapor phase) in the reservoir.

As the reservoir pressure declines isothermally during production from the initial pressure to the upper dew-point pressure, liquid begins to condense.

As the pressure is further decreased, instead of expanding (if a gas) or vaporizing (if a liquid) as might be expected, the hydrocarbon mixture tends to condense.

This retrograde condensation process continues with decreasing pressure until the liquid drop-out reaches its maximum, the dew-point curve must be crossed again. This means that all the liquid which formed must vaporize because the system is essentially all vapors at the lower dew-point.

Near-critical Gas-condensate Reservoir: If the reservoir temperature is near the critical temperature, the

hydrocarbon mixture is classified as a near-critical gas-condensate. Because all the quality lines converge at the critical point, a rapid liquid build-up immediately below the dew-point will result as the pressure is reduced.

This behavior can be justified by the fact that several quality lines are crossed very rapidly by the isothermal reduction in pressure. At the point where the liquid ceases to build up and begins to shrink again, the reservoir goes from the retrograde region to a normal vaporization region.

Wet Gas Reservoir:

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Reservoir temperature is above the cricondentherm of the hydrocarbon mixture. Because the reservoir temperature exceeds the cricondentherm of the hydrocarbon system, the reservoir fluid will always remain in the vapor phase region as the reservoir fluid will always remain in the vapor phase region as the reservoir is depleted isothermally.

The produced gas flows to the surface, the pressure and temperature of the gas will decline. If the gas enters the two phase region, a liquid phase will condense out of the gas and be produced from the surface separators.

Dry Gas Reservoir: The hydrocarbon mixture exists as a gas both in the reservoir and the surface facilities. The only liquid associated with the gas from a dry gas reservoir is water.Properties Of The Critical Point (Tc,Pc) (For Pure Substances):

1. Temperature and pressure for which liquid and vapor are no longer distinguishable.

2. For T > Tc, liquid and vapor will not co-exist, no matter what the pressure is.

3. For P > Pc, liquid and vapor will not co-exist, no matter what the temperature is.

Sensible Heat: Its main purpose is to cause an increase in temperature of the system.Latent Heat: It serves only one purpose: to convert the liquid into vapor. It does not cause a temperature increase.Critical Point (Pc, Tc): The temperature and pressure for which liquid and vapor are indistinguishable.Cricondentherm (Tcc):

1. The highest temperature in the two-phase envelope.2. For T > Tcc, liquid and vapor cannot co-exist at equilibrium, no matter

what the pressure is.Cricondenbar (Pcc):

1. The highest pressure in the two-phase envelope.2. For P > Pcc, liquid and vapor cannot co-exist at equilibrium, no matter

what the temperature is.For pure substances only:Cricondentherm = Cricondenbar = Critical Point.Flow equationsSeveral equations are available that relate the gas flow rate with gas properties, pipe diameter and length, and upstream and downstream pressures. These equations are listed as follows:1. General Flow equation 2. Colebrook-White equation 3. Modified Colebrook-White equation4. AGA equation, 5. Weymouth equation, 6. Panhandle A equation7. Panhandle B equation, 8. IGT equation, 9. Spitzglass equation10. Mueller equation, 11. Fritzsche equationGeneral flow equation – Isothermal flow equation in pipes

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The General Flow equation, also called the Fundamental Flow equation, for the steady-state isothermal flow in a gas pipeline is the basic equation for relating the pressure drop with flow rate. The most common form of this equation in the U.S. Customary System (USCS) of units is given in terms of the pipe diameter, gas properties, pressures, temperatures, and flow rate as follows.

Q = 77.54 D 2.5 ----------------- (1)Where,Q =gas flow rate, measured at standard conditions,F = friction factor, dimensionlessPb=base pressure, psiaTb=base temperature,°R(460+°F)P1=upstream pressure, psiaP2=downstream pressure, psiaG=gas gravity (air=1.00)Tf=average gas flowing temperature,°R (460+°F)L=pipe segment length, miZ=gas compressibility factor at the flowing temperature, dimensionlessD=pipe inside diameter, in.It must be noted that for the pipe segment from section 1 to section 2, the gas temperatureTf is assumed to be constant (isothermal flow).In SI units, the General Flow equation is stated as follows:

Q = 1.1494×10-4 D 2.5 --------- (2)Where,Q=gas flow rate, measured at standard conditions, m3/dayF =friction factor, dimensionlessPb=base pressure, kPaTb=base temperature, K (273+°C)P1=upstream pressure, kPaP2=downstream pressure, kPaG=gas gravity (air=1.00)Tf=average gas flowing temperature, K (273+°C)L=pipe segment length, kmZf=gas compressibility factor at the flowing temperature, dimensionlessD=pipe inside diameter, mm

Due to the nature of Equation 2, the pressures can also be in M Pa or bar, as long as the same consistent unit is used. Equation 1 relates the capacity (flow rate or throughput) of a pipe segment of length L, based on an upstream pressure of P1and a downstream pressure. It is assumed that there is no elevation difference

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between the upstream and downstream points; therefore, the pipe segment is horizontal. General Flow Equation 1, for a pipe segment of length L and diameter

D, the gas flow rate Q (at standard conditions) depends on several factors. Q depends on gas properties represented by the gravity G and the compressibility factor Z, If the gas gravity is increased (heavier gas), the flow rate will decrease.

Similarly, as the compressibility factor Z increases, the flow rate will decrease. Also, as the gas flowing temperature Tf increases, throughput will decrease. Thus, the hotter the gas, the lower the flow rate will be.

Therefore, to increase the flow rate, it helps to keep the gas temperature low. The impact of pipe length and inside diameter is also clear.

As the pipe segment length increases for given pressureP1andP2, the flow rate will decrease. On the other hand, the larger the diameter, the larger the flow rate will be. The term P12–P22 represents the driving force that causes the flow rate from the upstream end to the downstream end.

As the downstreampressureP2is reduced, keeping the upstream pressureP1constant, the flow rate will increase. It is obvious that when there is no flow rate, P1 is equal toP2.

It is due to friction between the gas and pipe walls that the pressure drop (P1–P2) occurs from the upstream point 1 to downstream point 2. The friction factor f depends on the internal condition of the pipe as well as the type of flow (laminar or turbulent) .General Flow equation is represented in terms of the transmission factor F instead of the friction factor f. This form of the equation is as follows.

Q = 38.77F D 2.5 -------------- (3)Where, the transmission factor F and friction factor f are related by

F = and in SI units

Q = 5.747×10-4 F D 2.5 -------------- (3)Weymouth equationThe Weymouth equation is used for high pressure, high flow rate, and large diameter gas gathering systems. This formula directly calculates the flow rate through a pipeline for given values of gas gravity, compressibility, inlet and outlet pressures, pipe diameter, and length. In USCS units, the Weymouth equation is stated as follows:

Q = 433.5E D 2.667 -------------- (1)Where,

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Q = volume flow rate, standard ft3/day (SCFD)E = pipeline efficiency, a decimal value less than or equal to 1.0Pb = base pressure, psiaTb = base temperature, °R (460 + °F)P1 = upstream pressure, psiaP2 = downstream pressure, psiaG = gas gravity (air = 1.00)Tf = average gas flow temperature, °R (460 + °F)Le = equivalent length of pipe segment, miZf = gas compressibility factor, dimensionlessD = pipe inside diameter, in.

Where, the equivalent length Le and s were defined earlier in and

s = 0.0375G By comparing the Weymouth equation with the General Flow equation, we can isolate an equivalent transmission factor as follows:The Weymouth transmission factor in USCS units isF = 11.18(D) 1/6

In SI units, the Weymouth equation is as follows:

Q =3.7435×10-3 E D 2.667 -------------- (1)Where, Q = gas flow rate, standard m3/dayTb = base temperature, K (273 + °C)Pb = base pressure, kPaTf = average gas flow temperature, K (273 + °C)P1 = upstream pressure, kPaP2 = downstream pressure, kPaLe = equivalent length of pipe segment, kmOther symbols are as defined previously.The Weymouth transmission factor in SI units isF = 6.521(D) 1/6

You will notice that a pipeline efficiency factor, E, is used in the Weymouth equation so we can compare the throughput performance of a pipeline using the General Flow equation that does not include an efficiency factor.

Darcy’s law and applicationsIntroductionDarcy's empirical flow law was the first extension of the principles of classical fluid dynamics to the flow of fluids through porous media. Darcy's law can be derived from the Navier-Stokes equation of motion of a viscous fluid.

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The significance of Darcy's law is that it introduces flow rates into reservoir engineering and, since the total surface oil production rate from a reservoir isq res = It implicitly introduces a time scale in oil recovery calculations. The practical application of this aspect of Darcy's law is given of the fundamental mechanics of well stimulation and enhanced oil recovery.Darcy’s law; fluid potential (gas flow in cylindrical reservoir, fundamentals of gas flow in porous media)

The equipment consisted of an iron cylinder containing an unconsolidated sand pack, about one metre in length, which was held between two permeable gauze screens.

Manometers were connected into the cylinder immediately above and below the sand pack. By flowing water through the pack Darcy established that, for any flow rate, the velocity of flow was directly proportional to the difference in manometric heights, the relationship being

U = K = Where, u = flow velocity in cm/sec, which is the total measured flow rate q cc/sec, divided by the cross-sectional area of the sand packΔh = difference in manometric levels, cm (water equivalent); I = total length of the sand pack, cm, and K = constant.

The irrespective of the orientation of the sand pack, the difference in height, Δh, was always the same for a given flow rate. Thus Darcy's experimental law proved to be independent of the direction of flow in the earth's gravitational field.

It is worthwhile considering the significance of the Δh term appearing in Darcy's law.

The pressure at any point in the flow path, which has an elevation z, relative to the datum plane, can be expressed in absolute units asp = ρ g(h-z) -------- (1)with respect to the prevailing atmospheric pressure. In this equation h is the liquid elevation of the upper manometer, again, with respect to z = 0 and ρ is the liquid (water) density. The equation can be alternatively expressed as

hg = ( +gz) --------- (2)If it’s written in differential form as U = K ------------ (3)then differentiating equ. (2) and substituting in equ. (3) Gives,

u = ( +gz) = --------- (4)

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The term ( + gz), in this latter equation, has the same unit as hg which is:Distance × force per unit mass, that is, potential energy per unit mass. This fluid potential is usually given the symbol Φ and defined as the work required, by a frictionless process, to transport a unit mass of fluid from a state of atmospheric pressure and zero elevation to the point in question, thus

Φ = + gz ------------- (5)Although defined in this way, fluid potentials are not always measured with respect to atmospheric pressure and zero elevation, but rather, with respect to any arbitrary base pressure and elevation (pb, zb) which modifies equ. (5) to,

Φ = + g(Z- Zb) ------- (6)

The reason for this is that fluid flow between two points A and B is governed by the difference in potential between the points, not the absolute potentials, i.e.

ΦA − ΦB = + g( - Zb) _ + g( - Zb) = + g( - ZB) ------ (7)

It is therefore conventional, in reservoir engineering to select an arbitrary, convenient datum plane, relative to the reservoir, and express all potentials with respect to this plane. Furthermore, if it is assumed that the reservoir fluid is incompressible (ρ independent of pressure) then equ. (5) can be expressed as

Φ = +gz ---- (7)Which, is precisely the term appearing in equ. (4). It can therefore be seen that the h term in Darcy's equation is directly proportional to the difference in fluid potential between the ends of the sand pack.The constant K/g is only applicable for the flow of water, which was the liquid used exclusively in Darcy's experiments. Experiments performed with a variety of different liquids revealed that the law can be generalized as

u = ----------- (8)In which the dependence of flow velocity on fluid density ρ and viscosity μ is fairly obvious. The new constant k has therefore been isolated as being solely dependent on the nature of the sand and is described as the permeability. It is, in fact, the absolute permeability of the sand, provided the latter is completely saturated with a fluid and, because of the manner of derivation, will have the same value irrespective of the nature of the fluid.

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Sign conventionDarcy's empirical law was described without regard to sign convention, it being assumed that all terms in equ. (8) were positive. This is adequate if the law is being used independently to calculate flow rates; however, if equ. (8) is used in conjunction with other mathematical equations.Linear flowIf, distance is measured positive in the direction of flow, then the potential gradient dΦ/dl must be negative in the same direction since fluids move from high to low potentialTherefore, Darcy's law is

u =- Radial flowIf production from the reservoir into the well is taken as positive, since the radius is measured as being positive in the direction opposite to the flow, dΦ/dr is positive and Darcy's law may be stated as

u = Radial steady state flow; well stimulation (General equations for radial flow of gases in symmetrical homogeneous reservoirs)

The mathematical description of the radial flow of fluids simulates flow from a reservoir, or part of a reservoir, into the wellbore.

For the radial geometry, flow will be described under what is called the steady state condition. This implies that, for a well producing at a constant rate q; dp/ dt = 0, at all points within the radial cell. Thus the outer boundary pressure pe and the entire pressure profile remain constant with time.

This condition may appear somewhat artificial but is realistic in the case of a pressure maintenance scheme, such as water injection, in which one of the aims is to keep the pressure constant. In such a case, the oil withdrawn from the radial cell is replaced by fluids crossing the outer boundary at r = re.

In addition, for simplicity, the reservoir will be assumed to be completely homogeneous in all reservoir parameters and the well perforated across the entire formation thickness.

Under these circumstances, Darcy's law for the radial flow of single phase oil can be expressed as

q = ---- (1)Since the flow rate is constant, it is the same across any radial area, A = 2πrh, situated at distance r from the centre of the system. Therefore, equ. (1) Can be expressed as

q = ---- (2)and separating the variables and integrating

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---- (3)

Where, pwf is the conventional symbol for the bottom hole flowing pressure. The integration results in

---- (4)Which, shows that the pressure increases logarithmically with respect to the radius, the pressure drop being consequently much more severe close to the well than towards the outer boundary. In particular, when r = re then

---- (5) When a well is being drilled it is always necessary to have a positive

pressure differential acting from the wellbore into the formation to prevent inflow of the reservoir fluids.

Because of this, some of the drilling mud will flow into the formation and the particles suspended in the mud can partially plug the pore spaces, reducing the permeability, and creating a damaged zone in the vicinity of the wellbore. The situation, in which ra represents the radius of this zone.

If the well were undamaged, the pressure profile for r < ra would be as shown by the dashed line, whereas due to the reduction in permeability in the damaged zone, equ. (5) Implies that the pressure drop will be larger than normal, or that pwf will be reduced. This additional pressure drop close to the well by skin

= S ---------- (6)in which the Δpskin is attributed to a skin of reduced permeability around the well and S is the mechanical skin factor, which is just a dimensionless number. This definition can be included in equ. (5) to give the total steady state inflow equation as

= S) --------- (7)in which it can be seen that if S is positive then pe - pwf the pressure drawdown, contains the additional pressure drop due to the perturbing effect of the skin. Since, equ. (7) is frequently employed by production engineers, it is useful to express it in field units rather than the Darcy units in which it was derived.The reader should check that this will give

= S) ------- (8)in which the geometrical factor 2π has been absorbed in the constant. This equation is frequently expressed as

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PI = =

PI = --------- (9)Where, the PI, or Productivity Index of a well, expressed in stb/d/psi, is a direct measure of the well performance.One of the aims of production engineering is to make the PI of each well as large as is practically possible, consistent with the economics of doing so. This is termed well stimulation. The ways in which a well can be stimulated can be deduced by considering how to vary the individual parameters in equ. (9) so as to increase the PI. Steady State condition (Radial flow)The steady state condition applies, after the transient period, to a well draining a cell which has a completely open outer boundary. It is assumed that, for a constant rate of production, fluid withdrawal from the cell will be exactly balanced by fluid entry across the open boundary and therefore,p = pe = constant, at r = re

and = 0 for all r and tThis condition is appropriate when pressure is being maintained in the reservoir due to either natural water influx or the injection of some displacing fluid.

UNIT-V - Multi phase flow terminologySuperficial velocity:The Superficial velocity is the velocity of one phase of a multiphase flow, assuming that the phase occupies the whole cross section of pipe by itself.

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It is defined for each phase as follows:VSW = QW/A ; VSO = QO/A ; VSG = QG/A; Where, A = AW + AO + AGThe parameter A is the total cross sectional area of pipe, Q is volumetric flow rate, V is velocity, and the subscripts are W for water, O for oil, G for gas and S for superficial term.Multiphase flow mixture velocity:Mixture velocity is the sum of phase superficial velocities:VM = VSW + VSO + VSGWhere , VM is the multiphase mixture velocity.HoldupHoldup is the cross-sectional area, which is locally occupied by one of the phases of a multiphase flow, relative to the cross sectional area of the pipe at the same local position.For the liquid phase,HL = AL/A = AW + AO/ A = HW + HOFor the gas phase, HG = AG/AWhere the parameter H is the phase holdup and the subscripts are L for the liquid and G for the gas phase.“Holdup” can be defined as the fraction of the pipe volume occupied by a given phase; holdup is usually defined as the in situ liquid volume fraction, where as the term “void fraction” is used for the in situ gas volume fraction.Phase velocityPhase velocity is the velocity of a phase of a multiphase flow based on the area of the pipe occupied by that phase. It may also be defined for each phase as follows:VL = VSL/ HL = VSW + VSO/ HLVL = VSG/ HGSlipSlip is the term used to describe the flow condition that exists when the phases have different phase velocities. The slip velocity is defined as the difference between actual gas and liquid velocities, as follows:VS = VG - VSLThe ratio between two-phase velocities is defined as the slip ratio. If there is no slip between the phases, VL = VG , and by applying the no-slip assumption to the liquid holdup definitionHL, no- slip =λL =VSL/ VMIt’s not often applicable. For certain flow patterns in horizontal and upward inclined pipes, gas tends to flow faster than the liquid (positive slip). For some flow regimes in downward flow, liquid can flow faster than the gas (negative slip).Multiphase flow densityEquations for two-phase gas/liquid density ρS = ρL HL + ρG HG ----------------------------------- (i)ρn = ρL λL + ρG λG ----------------------------------- (ii)ρk = ρL λL 2/ HL + ρG λG2 /HG ---------------------------------------(iii)

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Equation (i) is used to determine the pressure gradient due to elevation change. Some correlations are based on the assumption of no slippage and therefore use equation (ii) for two phase density.Equation (iii) is used to define the density used in the friction loss term and in the Reynolds number. The total density determined from the oil and water densities and flow rates if no slippage between these liquid phases is assumed:ρL = ρO fO+ ρW fWWhere fO = QO/QO + QW= 1- fW

Where, the parameter f is the volume fraction of each phase.1. Multiphase flow regimes

Multiphase flow is a complex phenomenon that is difficult to understand, predict, and model.

Common single-phase flow characteristics such as velocity profile, turbulence, and boundary layer are thus inappropriate for describing the nature of such flows.

The flow structures are rather classified in flow regimes, whose precise characteristics depend on a number of parameters.

Flow regimes vary depending on operating conditions, fluid properties, flow rates, and the orientation and geometry of the pipe through which the fluids flow.

The transition between different flow regimes may be a gradual process. Due to the highly nonlinear nature of the forces that rule the flow regime transitions, the prediction is near impossible.

1.1 Two-Phase Flow Regimes The description of two-phase flow can be simplified by classifying types

of gas–liquid interfacial distribution and calling these “flow regimes” or “flow patterns.”

The distribution of the fluid phases in space and time differs for the various flow regimes and is usually not under the control of the pipeline designer or operator.

1.1.1. Horizontal Flow Regimes1.1.1. i. Stratified (Smooth and Wavy) Flow

Stratified flow consists of two superposed layers of gas and liquid, formed by segregation under the influence of gravity.

The gas–liquid interface is more or less curved and either smooth or rough because of capillary or gravity forces. The curvature of the interface increases with the velocity of the gas phase

1.1.1. ii. Intermittent (Slug and Elongated Bubble) Flow The intermittent flow regime is usually divided into two sub regimes:

plug or elongated bubble flow and slug flow. The elongated bubble flow regime can be considered as a limiting case of slug flow, where the liquid slug is free of entrained gas bubbles.

Flow regimes are quite similar to each other, their fluid dynamic characteristics are very different and greatly influence such quantities as pressure drop and) slug velocity.

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Gas–liquid intermittent flow exists in the whole range of pipe inclinations and over a wide range of gas and liquid flow rates.

It is characterized by an intrinsic unsteadiness due to regions in which the liquid slugs fill the whole pipeline cross section and regions in which the flow consists of a liquid layer and a gas layer.

The presence of these slugs can often be troublesome in the practical applications (giving rise to sudden pressure pulses, causing large system vibration and surges in liquid and gas flow rates), and the prediction of the onset of slug flow is of considerable industrial importance.

1.1.1. iii. Annular Flow: During annular flow, the liquid phase flows largely as an annular film

on the wall with gas flowing as a central core some of the liquid is entrained as droplets in this gas core.

The annular liquid film is thicker at the bottom than at the top of the pipe because of the effect of gravity and, except at very low liquid rates, the liquid film is covered with large waves.

1.1.1. iv. Dispersed Bubble Flow: At high liquid rates and low gas rates, the gas is dispersed as bubbles

in a continuous liquid phase. The bubble density is higher toward the top of the pipeline, but there are bubbles throughout the cross section.

Dispersed flow occurs only at high flow rates and high pressures. This type of flow, which entails high-pressure loss, is rarely encountered in flow lines.

Note that raw gas pipelines usually have stratified smooth/wavy flow patterns. This arises because flow lines are designed to have appreciable velocities and the liquid content is usually quite low.

Annular flow can also occur but this corresponds to high velocities, which are avoided to prevent erosion/corrosion, etc. In other words, raw gas lines are “sized” to be operated in stratified flow during normal operation.

1.1.2. Vertical Flow RegimesFlow regimes frequently encountered in upward vertical two-phase flow. These flow regimes tend to be somewhat simpler than those in horizontal flow. This results from the symmetry in the flow induced by the gravitational force acting parallel to it. 1.1.2. i. Bubble Flow The gas phase is distributed in the liquid phase as variable-size, deformable bubbles moving upward with zigzag motion. The wall of the pipe is always contacted by the liquid phase.1.1.2. ii Slug Flow

Most of the gas is in the form of large bullet-shaped bubbles that have a diameter almost reaching the pipe diameter.

These bubbles are referred to as “Taylor bubbles,” move uniformly upward, and are separated by slugs of continuous liquid that bridge the pipe and contain small gas bubbles.

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Typically, the liquid in the film around the Taylor bubbles may move downward at low velocities, although the net flow of liquid can be upward. The gas bubble velocity is greater than that of the liquid.

1.1.2. iii. Churn Flow If a change from a continuous liquid phase to a continuous gas phase

occurs, the continuity of the liquid in the slug between successive Taylor bubbles is destroyed repeatedly by a high local gas concentration in the slug.

This oscillatory flow of the liquid is typical of churn flow. It may not occur in small-diameter pipes. The gas bubbles may join and liquid may be entrained in the bubbles.

1.1.2. iv. Annular Flow Annular flow is characterized by the continuity of the gas phase in the

pipe core. The liquid phase moves upward partly as a wavy flow and partly in the form of drops entrained in the gas core.

Although downward vertical two-phase flow is less common than upward flow, it does occur in steam injection wells and down comer pipes from offshore production platforms.

Three-Phase Flow Regimes The main difference between two-phase (gas/liquid) flows and three-

phase (gas/liquid/liquid) flows is the behavior of the liquid phases, where in three-phase systems the presence of two liquids gives rise to a rich variety of flow patterns.

Basically, depending on the local conditions, the liquid phases appear in a separated or dispersed form. In the case of separated flow, distinct layers of oil and water can be discerned, although there may be some inter entrainment of one liquid phase into the other.

In dispersed flow, one liquid phase is completely dispersed as droplets in the other, resulting in two possible situations, namely an oil continuous phase and a water continuous phase. The transition from one liquid continuous phase to the other is known as phase inversion.

2. Calculating multiphase flow pressure gradients The hydraulic design of a multiphase flow pipeline is a two-step

process. The first step is the determination of the multiphase flow regimes

because many pressure drop calculation methods rely on the type of flow regime present in the pipe.

The second step is the calculation of flow parameters, such as pressure drop and liquid holdup, to size pipelines and field processing equipment, such as slug catchers.

2.1.Steady-State Two-Phase FlowThe techniques used most commonly in the design of a two-phase flow pipeline can be classified into three categories: single-phase flow approaches, homogeneous flow approaches, and mechanistic models.2.1.1. Single-Phase Flow Approaches

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In this method, the two-phase flow is assumed to be a single-phase flow having pseudo-properties arrived at by suitably weighting the properties of the individual phases.

Single-phase flow approaches were used commonly for the design of wet gas pipelines.

When the amount of the condensed liquid is negligibly small, the use of such methods could at best prevent under design, but more often than not, the quantity of the condensed liquid is significant enough that the single-phase flow approach grossly over predicted the pressure drop.

2.1.2. Homogeneous Flow Approaches The inadequacy of the single-phase flow approaches researchers to

develop better design procedures and predictive models for two-phase flow systems. This effort led to the development of homogeneous flow approaches to describe these rather complex flows.

The homogeneous approach, also known as the friction factor model, is similar to that of the single-phase flow approach except that mixture fluid properties are used in determination of the friction factor.

Therefore, the appropriate definitions of the fluid properties are critical to the accuracy of the model.

The mixture properties are expressed empirically as a function of the gas and liquid properties, as well as their respective holdups.

Many of these correlations are based on flow regime correlations that determine the two-phase (gas/liquid) flow friction factor, which is then used to estimate pressure drop.

1. Lockhart and Martinelli Method, 2. Beggs and Brill Method2.1.2.1 Lockhart and Martinelli Method: This method was developed by correlating experimental data generated in horizontal isothermal two phase flow of two-component systems (air–oil and air–water) at low pressures. The two-phase frictional pressure drop is calculated by multiplying by a correction factor for each phase, as follows:

dp/ dx = Φ2G(dp/ dx)G = Φ2L (dp/ dx)L Where,

(dp/ dx)G = (fGρGV2SG / 2gc D) ; (dp/ dx)L = (fLρLV2SL/ 2gc D)

The friction factors fG and fL are determined from the Moody diagram using the following values of the Reynolds number:

N Re,G = (ρGVSGD/ µG); N Re,L = (ρLVSLD/ µL)

The two-phase flow correction factors (ΦG, ΦL) are determined from the relationships of Equations

Φ2G = 1 + CX + CX2 ; Φ2L = 1 + CX + CX2

Where,

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X

=[( dpdx )L

( dpdx )G]0. 5

Where, Parameter C has the values shown in table. Note that the laminar flow regime for a phase occurs when the Reynolds number for that phase is less than 2000.In this method, the correlation between liquid holdup and Martinelli parameter, X, is independent of the flow regime and can be expressed as follows:

HL-2 =1+(20

X )+( 1X2)

C ParameterLiquid phase Gas phase CTurbulent Turbulent 20Laminar Turbulent 12Turbulent Laminar 10Laminar Laminar 5

2.2.Steady-State Three-Phase Flow The complex nature of such flows makes prediction very difficult.

Treated the two immiscible liquid phases as a single fluid with mixture properties, thus a two-phase flow correlation could be used for pressure loss calculations.

Two-phase flow correlations for gas–liquid two-phase flow can be used as the basis in the determination of three-phase flow parameters; hence, an appropriate model is required to describe the flow of one gas and two liquid phases.

One of the most fundamental approaches used to model such systems is the two-fluid model, where the presented approach can be used by combining the two liquid phases as one pseudo-liquid phase and modeling the three-phase flow as a two-phase flow.

Three-fluid models should be used to account for the effect of liquid–liquid interactions on flow characteristics, especially at low flow rates.

2.3.Transient Multiphase Flow Transient multiphase flow in pipelines can occur due to changes in inlet

flow rates, outlet pressure, opening or closing of valves, blow down, ramp-up, and pigging.

In each of these cases, detailed information of the flow behavior is necessary for the designer and the operator of the system to construct and operate the pipeline economically and safely.

The steady-state pipeline design tools are not sufficient to adequately design the operational flexibility of multiphase pipelines.

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Therefore, a model for predicting the overall flow behavior in terms of pressure, liquid holdup, and flow rate distributions for these different transient conditions would be very useful.

Transient multiphase flow is traditionally modeled by one-dimensional averaged conservation laws, yielding a set of partial differential equations. • The two-fluid model (TFM), consisting of a separate momentum equation for each phase.• The drift-flux model (DFM), consisting of a momentum equation and an algebraic slip relation for the phase velocities.The following major assumptions have been made in the formulation of the differential equations.1. Two immiscible liquid phases (oil and water) that are assumed to be a single fluid with mixture properties.2. Flow is one dimensional in the axial direction of the pipeline.3. Flow temperature is constant at wall, and no mass transfer occurs between gas and liquid phases. Note that most commercial codes allow phase change.4. The physical properties of multiphase flow are determined at the average temperature and pressure of flow in each segment of the pipeline.2.3.1 Two-Fluid ModelThe TFM is governed by a set of four partial differential equations, the first two of which express mass conservation for gas and liquid phases, respectively,

∂∂ t [ ρGHG ]+ ∂

∂ x [ ρGHGV G ]=0

Similarly for liquid phaseThe last two equations represent momentum balance for the gas and liquid phases, respectively,∂∂ t [( ρGHGV G ) ]

+∂∂ x [ρGHGV

2G+HG ΔPG ]+HGΔPΔX = τG+ τi− ΔG g sin θ

Similarly, liquid phaseParameter P denotes the interface pressure, whereas VK, φ K, and HK are the velocity, the density, and the volume fraction of phase k {G, L}, respectively. The variables φ i and φ k are the interfacial and wall momentum transfer terms. The quantities ΔPG and ΔPL correspond to the static head around the interface defined as follows:

ΔPG=ΔPG−P=−ρG [1 /2COS (ω/2 )+(1/3 ΔHG )Sin3 (ω/2 ) ] gdCOSθSimilarly for liquid phase, replace the G by L. Where, φ is the wetted

angleDrift Flux Model:

The DFM is derived from the TFM by neglecting the static head terms ΔPG, ΔPL and replacing the two momentum equations by their sum. The main advantages of this three-equation model are as follows:

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i) The equations are in conservative form, which makes their solution by finite volume methods less onerous.

ii) The interfacial shear term, φ i, is cancelled out in the momentum equations, although it appears in an additional algebraic relation called the slip law.

iii) The model is well posed and does not exhibit a complex characteristic.

∂∂ t [ ρGHGV G+ ρlHLV L ]+ ∂

∂ t [ρGHGV2G+ ρLH LV

2L+P ]=τG−τ L−(ρGHG+ρLHL )sin θ

Drift flux approach is best applied to closely coupled flows such as bubbly flow. Its application to stratified flows is, at best, artificial.

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pe 505 natural gas engineering

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