doc - 10 gas conditioning system

8/10/2019 Doc - 10 Gas Conditioning System

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LARSEN & TOUBRO LIMITED EPC POWER

TRAINING MANUAL

PROJECT 388.5 MW Combined Cycle Power Plant DOC No. IBDC/ L&T/ VCCPP/ 10

DOC. TITLE Gas Conditioning System Page No. Page 1 of 24

Gas Conditioning System

Sources of Natural Gas Production

Natural gas produced from geological formations comes in a wide array ofcompositions. The varieties of gas compositions can be broadly categorized intothree distinct groups:

Associated Gas,

Non-Associated Gas Coal Bed Methane.

These produced gases can contain both hydrocarbon based gases (those which

contain hydrogen and carbon) and non-hydrocarbon gases.Hydrocarbon gases are Methane (C1), Ethane (C2), Propane (C3), Butanes (C4),Pentanes (C5), Hexanes (C6), Heptanes (C7), Octanes (C8), and Nonanes plus(C9+). The non-hydrocarbon gas portion of the produced gas can contain Nitrogen

(N2), Carbon Dioxide (CO2), Helium (He), Hydrogen Sulfide (H2S), water vapor(H2O), Oxygen (O2), other sulfur compounds and trace gases. CO2 and H2S are

commonly referred to as acid gases since they form corrosive compounds in thepresence of water. N2, He and CO2 are referred to as diluents since none of these

burn, and thus they have no heating value.

The composition of Natural Gas that is available at Vimagiri Plant is as

followed.

Calorific value: LCV - 8489 kcal/Sm3(kJ/kg); GCV 9382 kcal/Sm3(kJ/kg) and

The specific gravity is 0.6854


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Role of Gas conditioning: To determine the suitability for operation with a gas fuelsystem, various physical parameters of the proposed fuel need to be determined:Heating value, dew point, Joule-Thompson coefficient, Wobbe Index and others.

However, fuel borne contaminants can also cause engine degradation. Special focusis given to the problem of determining the dew point of the potential fuel gas at

various pressure levels. In particular the treatment of heavier hydrocarbons, andwater is addressed and recommendations about the necessary data input are made.Since any fuel gas system causes pressure drops in the fuel gas, the temperature

reduction due to the Joule-Thompson effect has to be considered and quantified.

The quality and composition of fuel burned in a gas turbine impacts the life of theturbine, particularly its combustion system and turbine section. The fuel specified for

a given application is usually based on availability and price. Natural gas is a typicalfuel of choice for gas turbines due to its low cost, widespread availability and lowresulting emissions. However, the composition of fuel gas can widely vary, from gaswith significant amounts of heavier hydrocarbons1 (Butane and heavier), to pipeline

quality gas consisting mostly of methane, to fuel gas with significant amounts of

noncombustible gases (such as Nitrogen, or Carbon Dioxide).

Gas fuels for gas turbines are combustible gases or mixtures of combustible andinert gases with a variety of compositions covering a wide range of heating values

and densities. The combustible components can consist of methane and other lowmolecular weight hydrocarbons, hydrogen and carbon monoxide. The major inertcomponents are nitrogen, carbon dioxide and water vapor. It is generally accepted

that this type of fuel has to be completely gaseous at the entry to the fuel gassystem and at all points downstream to the fuel nozzle.

Gaseous fuels can vary from poor quality wellhead gas to high quality consumer orpipeline gas. In many systems, the gas composition and quality may be subject tovariations.

Typically, the major sources of contaminants within these fuels are: Solids Water

Heavy gases present as liquids Oils typical of compressor oils Hydrogen sulfide (H2S)

Hydrogen (H2) Carbon monoxide (CO) Carbon dioxide (CO2) Siloxanes

Other factors that will affect turbine or combustion system life and performance

include lower heating value (LHV), specific gravity (SG), fuel temperature, andambient temperature. Some of these issues may co-exist and be interrelated. Forinstance, water, heavy gases present as liquids, and leakage of machinery lubricating

oils, may be a problem for turbine operators at the end of a distribution or branchline, or at a low point in a fuel supply line.Water in the gas may combine with other small molecules to produce a hydrate asolid with an ice-like appearance. Hydrate production is influenced, in turn, by gas

composition, gas temperature, gas pressure and pressure drops in the gas fuelsystem. Liquid water in the presence of H2S or CO2 will form acids that can attackfuel supply lines and components. Free water can also cause turbine flameouts or

operating instability if ingested in the combustor or fuel control components.


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Heavy hydrocarbon gases present as liquids provide many times the heating value

per unit volume than they would as a gas. Since turbine fuel systems meter the fuelbased on the fuel being a gas, this creates a safety problem, especially during the

engine start-up sequence when the supply line to the turbine still may be cold.

Hydrocarbon liquids can cause:

- Turbine overfueling, which can cause an explosion or severe turbine damage).

- Fuel control stability problems, because the system gain will vary as liquidslugs or droplets move through the control system.

- Combustor hot streaks and subsequent engine hot section damage.

- Overfueling the bottom section of the combustor when liquids gravitate

towards the bottom of the manifold

- Internal injector blockage over time, when trapped liquids pyrolyze in the hotgas passages.

Liquid carryover is a known cause for rapid degradation of the hot gas pathcomponents in a turbine.

The condition of the combustor components also has a strong influence and fuelnozzles that have accumulated pipeline contaminants that block internalpassageways will probably be more likely to miss desired performance or emission

targets. Thus, it follows that more maintenance attention may be necessary toassure that combustion components are in premium condition. This may require thatfuel nozzles be inspected and cleaned at more regular intervals or that improved fuelfiltration components be installed.

Figure 1: Schematic of a Gas Fuel system, showing the pressure drop in various devices. If thegas is not superheated sufficiently, its temperature will eventually fall below the dew point

temperature.With a known gas composition, it is possible to predict dew point temperatures forwater and hydrocarbons. However, the prediction methods for dew points may not


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always be accurate. In fact, it is known that different equations of state will yield

different calculated dew points under otherwise identical conditions. Furthermore,the temperature in an unheated fuel line will drop, because the pressure drop due to

valves and orifices in the fuel line causes a temperature drop in the gas (Figure 1).This effect is known as the Joule-Thompson effect. Most fuel gases (except

hydrogen) will exhibit a reduction in temperature during an adiabatic throttling.Hydrogen on the other hand actually shows an increased temperature when thepressure drops, which is a potential explosion hazard.

Figure 2: Schematic of Typical Oil or Gas Platform Fuel Conditioning System

Protection against heavy gases and water present as liquids can be achieved by

heating the fuel downstream of knockout drums and coalescing filters Figure 2. Theidea is to have a saturated gas at the exit of the knockout drum and filters and thento raise the temperature to the necessary superheat to prevent subsequent liquiddropout. The system shown in Figure 2 is typical for fuel systems on oil or gasplatforms, where the gas produced is usually wet. For dry gas of well known

composition, such as from gas plants or for pipeline applications, a less complexsystem may be appropriate Figure 3.

Figure 3. Schematic of Gas Pipeline Fuel Delivery System with Gas at Greater than MinimumSuperheat


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Figure 1 illustrates the necessity for a superheat of about 50F (28 K) over the dew

point to ensure that no liquid dropout appears in the fuel system componentsdownstream of the heater. A superheating requirement of 50F (28 K) is currently

acknowledged as an industry standard (ASME, 1992). The heat input yielded by aspecific gas fuel is determined by the gas composition (including the moisture

content), its mass flow, and its heating value. Performance representations for gasturbines are usually based on the lower heating value of the fuel gas, because theexhaust temperatures are always high enough to keep the water vapor in theexhaust from condensing.

A gas analysis alone may not be entirely sufficient for the detection of heavyhydrocarbons, because it may only include the gases, but not the liquids in thestream. Also, it is common practice to lump all hydrocarbons from Hexane and

heavier into one number. While this is perfectly acceptable for the calculation of thelower heating value as long as the Hexane and heavier hydrocarbons constitute aminute fraction of the gas, it will lead to a wrong estimate of the dew point. C14H30,even in parts-per-million amounts has a significant impact on the dew point of the

gas mixture, as we will show later. Certainly a gas analysis has to be used in the

project stage to allow for equipment sizing. Also, fuel systems usually limit the gassupply temperature due to temperature limits of its components. If the necessarysuperheat temperature exceeds the fuel system temperature limits, additional gastreatment may be necessary.

Lower Heating Value, Specific Gravity, Fuel Temperature, and Ambient Temperatureare important parameters since they influence the energy of the fuel flowing in thesystem. From the lower heating value (LHV) in Btu/scf [kJ/Nm3] and the specificgravity (SG), the Wobbe Index (WI) of the gas can be calculated:

Because the fuel supply temperature Tf has an impact on the actual volumetric fuelflow, a temperature corrected Wobbe Index is often used, where the reference

Temperature Tref is usually 520 R or 288K:

If two different fuel gas compositions have the same Wobbe Index, the pressuredrop in a given fuel system will be the same for both gases. The Wobbe Index is thus

an indication of energy flow in the system at the same gas pressures and pressuredrops.A standard fuel system may for example be designed for a Wobbe Index of 122010% Btu/scf (48,031 10% kJ/ Nm3) based on the LHV of the fuel. Different gas

compositions can yield the same Wobbe Index, but they will have widely differenthydrocarbon dew points. Minimum engine flameout fuel flows will also vary if the fuel

contains high percentages of noncombustible gases. High fuel gas or ambienttemperatures can cause problems if the temperature capabilities of elastomericseals, electrical devices or other system components are exceeded. Low fuel gas orambient temperatures can cause water or heavy hydrocarbon condensation.

Protection against these factors includes analyzing the variations in the fuelcomposition, fuel temperature, and ambient temperature so that the required

modifications to the fuel treatment system and turbine fuel system can be made. Aturbine expected to operate with gaseous fuels exhibiting a wide Wobbe Index rangewill need to be configured differently than one that will only operate with a small

variance in Wobbe Index. The fuel supply contract should include the allowable


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variations in composition and temperature. The probability of upset conditions needs

to be evaluated and fuel treatment systems and turbine fuel systems need to bedesigned for the upset conditions. Gas fuel supply and package lines may need to be

heat traced to keep the gas fuel supply above the gas dew point during periods whenthe engine is not operating. Low point drains are also recommended if liquids may be

present in the gas fuel. This precludes burying the gas fuel supply lines undergroundwhen liquids may be present.

Low BTU Fuel Gas

The potential concerns about burning low BTU fuel gas in a gas turbine arise ingeneral around three topics:

1- Can a stable combustion be maintained?

2- Can emissions requirements be met?3- How does the fuel gas affect gas turbine operation?

A significant number of gas turbines operate successfully using low BTU fuels.

Landfill gas, for example, is usually of very low BTU content due to the high

percentage of CO2 (typically around 40%) in the fuel gas. Stable combustiondepends on the capability of the fuel system to deliver sufficient amounts of fuel tosustain the combustion process. Low BTU fuels often have a limited flammabilityrange. This cans which can require the addition of gas with heavier hydrocarbons

(e.g. Propane) during start-up, at low load, or during transients. Of importance isalso the capability of the torch to ignite the fuel to initiate combustion. As describedearlier, the fuel to air ratio of an engine, without additional measures, tends to causeleaner mixtures at low loads. Another concern could be the requirement for sufficient

residence time in the combustor.

Low-BTU fuels will burn at a lower flame temperature than standard natural gas

Figure 4,assuming the low energy content is due to noncombustible gases. A lowerflame temperature will reduce the amount of NOx generated. The dilutants (such as

Nitrogen or CO2) effectively cool the flame, thus generating a lower rate of NOx. Theemissions from a low BTU fuel are therefore easier to handle than the emissions from

standard natural gas.Another question is related to gas turbine performance. The function of gas turbineand its components was described earlier: The power needed in the air compressor isproportional to the mass flow through the compressor and the power generated in

the turbine section is proportional to the mass flow through the turbine section. Themass flow through the turbine section is the sum of air mass flow through thecompressor and fuel mass flow (neglecting steam or water injection and bleed air).

For a low BTU fuel, the fuel mass flow increases compared to the fuel mass flow ifthe engine were to operate on natural gas. The fuel flow adds about 1.5 to 2 percentto the air mass flow if natural gas is used, but a low BTU gas with LHV of 10 MJ/kgcould require a fuel flow that adds 7 to 10 percent to the air mass flow.


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Figure 4: Impact of Fuel Gas on Emissions

Therefore, the mass flow through the turbine section is increased, while the

compressor air mass flow remains the same. The increased exhaust mass flowmoves the compressor operating point to a slightly higher discharge pressure, whichmeans the compressor consumes somewhat more power. The net effect is a higher

power output of the engine. The engine compressor needs to have sufficient stallmargin, because the added mass flow will move the operating points closer to thestall line of the compressor. Steam or water injections into the combustor have asimilar effect.

Dew pointFor fuel gas containing heavier hydrocarbons or water, the temperature of the gashas to be high enough to avoid the dropping out of liquids. The dew pointtemperature of a gas is the temperature at a given pressure at which the first drop

of liquid forms in equilibrium with the gas.When a real gas experiences a drop in pressure (e.g. due to a flow orifice or avalve), and no heat or work is exchanged with the environment, the temperature ofthe gas will change. The enthalpy of the gas stays constant. This behavior is called

Joule-Thompson Effect. The temperature will actually drop for most gases (inparticular hydrocarbons) except hydrogen when the pressure is reduced. Since anyfuel system will cause a pressure drop to the fuel , fuel gas that is above the dewpoint at the fuel system inlet, could experience liquid drop out due to this drop in

temperature. The situation is often aggravated by heat loss of the fuel system whenthe surrounding temperature is lower than the fuel supply temperature.

Because the calculation of the dew point temperature, the enthalpy at the dew point,and the enthalpy of the gas mixture at various pressures is so important, we willdiscuss it in more detail. The necessary calculations are performed using a suitableequation of state. These semi-empirical correlations allow, for a known gascomposition, to calculate the dew point temperature and dew point enthalpy for a

given pressure. They also allow to calculate the enthalpy of the gas for givenpressures and temperatures. Thus, as long as the enthalpy of the gas is higher thanthe enthalpy at the dew point (for a given pressure), no liquid dropout will occur. The

basis for performing a dew point calculation is the understanding that it is anequilibrium state. The fundamental thermodynamic relation for phase equilibria, suchas the dew point, is that the fugacity of each component in the vapor phase is equal


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to the fugacity of the same component in the liquid phase. This arises because the

fugacity is a measure of the "escaping tendency" for a component to leave its phase.Thus, when a component's fugacity is the same in two or more homogeneous phases

in contact, there will be no net mass transfer, i.e., equilibrium exists. The fugacitycoefficient is calculated using an equation of state.

If water is present in the gas, then the problem becomes more complex. Though thesystems of interest are mostly alkanes and, in some cases, non-polar inorganicgases, an aqueous phase may be formed at a higher temperature than the organicphase. The dew point calculated is not necessarily the relevant one, since it is

possible for the organic phase to drop out first. The preferred method is to calculateboth the dew point where the organic phase drops out first and the dew point wherethe aqueous phase drops out first, and then to choose whichever temperature is

larger.

Figure 5: Dew line for different gas mixtures in a pressure(bar)-temperature(K) diagram. Gas

composition is: Methane 73.8%,Ethane 8.2%,Propane 3.23%, I-Butane .28%, n-Butane 0.78%, I-

Pentane 0.24%,n-Pentane 0.18%, n-Hexane 0.18%, Cxx 0.71%, Nitrogen 0.93%, Carbondioxide11.68%. Cxx represents either Hexane (C6), Octane(C8) or Decane(C10). Despite the fact that Cxx

represents only 0.71% of the gas, it has a significant impact on the dew point.

To conduct a successful determination of the fuel system capability, the fuel gas

composition, possible contaminants, the fuel supply pressure and temperature needto be known. As part of this study, it became obvious that the dew point of ahydrocarbon gas mixture is highly dependent on the heavier hydrocarbons. Thecommon practice to report Hydrocarbons individually only up to pentane, and lump

all heavier hydrocarbons into one C6+ number may yield sufficient information aboutthe lower heating value and the Wobbe Index of the fuel. It will not yield an accuratedew point, however. In Figure 5, a typical situation is evaluated: A fuel gascomposition has 0.71 percent of its constituents lumped together as C6+.

Then, dew points are calculated assuming these constituents are either all Hexane,or all Octane or all Undecane. As Figure 5 shows, even small amounts of heavierhydrocarbons have a significant effect on the dew point of the gas mixture.


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Arguably, the practice to remove all liquids in a separator, and then to heat the gas

portion by, say 50F (28 K), will insure that the gas supplied to the gas turbine willindeed be superheated by 50F (28K).

However, a proper sizing of the heater is not possible without knowing (at leastapproximately), the required end temperature. Also, fuel system components usually

have maximum allowable temperatures. Without prior knowledge of the necessarygas temperature, the fuel system temperature limits may not allow the necessarysuperheat.It must be noted that all the prior statements assume an adiabatic fuel system. Heat

loss in the fuel system will occur, however, if the system is not insulated and thesurrounding temperature is significantly lower than the fuel supply temperature. Inparticular during start-up at low ambient temperatures, when the fuel system is still

cold liquids can form. A system without heat tracing needs to be evaluated assumingthe lowest surrounding temperature. However, standard heat transfer methods allowapproximating the heat loss of a fuel system under arbitrary surrounding conditions,and using the first law of thermodynamics, to calculate the fuel gas enthalpy at any

point of the fuel system. As described above, this enthalpy has to be higher than the

enthalpy of the vapor at the dew point.

Avoidance of Liquid DropoutMany gas turbine installations operate with very simple fuel supply systems,

especially if the fuel composition and supply temperature and pressure are constant.If the fuel analysis determines that there will not be any liquid dropout under anyoperating condition with sufficient superheat margin, the system as outlined inFigure 3 should be sufficient. In applications where the fuel quality is subject to

significant change, or where a sufficient margin of superheat cannot be ensured, afuel system as outlined in Figure 2 is more appropriate.In such a fuel system with a separator and subsequent heater, the fuel will leave the

separator in a saturated state (either saturated with water or heavy hydrocarbons).The temperature increase in the heater is thus equal to the amount of superheat of

the gas. On a side note, for a given required amount of superheating, the requiredheat input of the heater PH is approximately:

The heater can be electric, or use hot water; exhaust heat can also be used to heatfuel, using heat exchangers.To determine whether the system will be capable ofavoiding liquid drop out, the enthalpy of the fuel gas has to be calculated at the skidedge. Knowing the gas composition, the gas pressure and the gas temperature at

skid edge allows calculating the enthalpy of the gas. The pressure in the combustordepends on the engine load (Figure 6). The exact slope of combustor pressureversus load depends on the design of the engine; in particular whether it is a single

or two-shaft engine, and the type of engine controls used. We further assume that

the velocities in the fuel system stay low (i.e. there is no significant differencebetween the static and the total enthalpy). The necessary condition to avoid liquiddrop out in an adiabatic fuel system is, that for all pressure levels that may occur inthis fuel system, the enthalpy of the vapor at the dew point is lower than theenthalpy of the gas at the skid edge (Figure 6).

This approach does obviously not account for the effect of high velocities in the fuelsystem, as they can occur in partially closed valves. These high velocities can lead toa significant drop in the enthalpy, and can easily cause a situation where liquids drop

out. However, this situation is not as critical as it looks at the first glance. First, thevelocities will drop again after the valve. The static enthalpy will therefore increase,so even if droplets may have formed, they will evaporate again. Second, it is known


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that in situations with rapidly accelerated gas there is a time lag between the

condition where the state of the gas would indicate liquid droplets and the actualformation of droplets. This effect is frequently experienced in steam turbines, where,

during the rapid acceleration of the steam in the nozzles, steam can be substantiallysupercooled without forming liquids.

Under quasi -stationary conditions, we can easily describe the change of states fromskid edge to the exit of the fuel injector into the combustor. The conditions at skidedge are known, and the engine compressor exit pressure or the actual combustor

pressure can be used to approximate the pressure at the injector exit. The path in aMollier diagram is shown in Figure 6. The dew line, which is typical for hydrocarbonfuel gas, shows a distinct maximum H/p =0. The shape of the dew line thus

suggests, that the highest chance of liquid dropout occurs not necessarily at thelowest pressure in the combustor.

Figure 6: Engine compressor discharge pressure (PCD) as a function of engine load, andthe resulting process path of fuel gas in an adiabatic fuel system.

In evaluating these fuel systems, one must take into account that the highest

pressure drops in the fuel system may not occur at full load, but rather during thestarting of the engine, when the combustor pressure is lowest (Figure 6). In otherwords, the system has to be evaluated for the highest pressure that the gas canhave at skid edge, and the combustor pressure at light-off conditions, as well as for

any load condition between idle and full load.Additionally, unless the fuel lines are heat traced, they may be colder than the fuelespecially during start up. Therefore, a significant safety margin between the dewpoint temperature and the lowest possible fuel temperature is necessary.

Hydrogen SulfideHydrogen sulfide (H2S) causes a number of challenges to the operation of a gas

turbine. The fact that it is highly toxic requires sufficient protection of personnel fromleakages. Hydrogen sulfide and CO2 form acids in the presence of liquid water. Sincemany fuels are water saturated, sufficient superheat over the water dew point of the

fuel as well as heat tracing has to be provided, to avoid corrosion of the fuel system.The Sulfur contained in Hydrogen Sulfide (as well as in Mercaptanes) will react in thecombustion process to from SO2 and SO3. These gases are often regulated because

they can cause acid rain.Additionally, if sulfur has the opportunity to react with sodium or potassium (whichoften is introduced with the combustion air, especially in offshore applications) in the


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combustor, it will form alkali sulfates that can cause hot corrosion in the hot section

of the gas turbine. It is important to note that hot corrosion is often caused by theinteraction between fuel quality and air filtration quality.

Operation with fuel pressure limitations

The gas fuel supply pressure has to be high enough to overcome the pressure lossesin the fuel system, and the pressure in the combustor at the injector tip. If the fuel

pressure is too low, the engine output is no longer limited by firing temperature orspeed limitations, but by the fuel pressure. The combustor pressure is typically lowerat high ambient temperatures (because for the same compressor head, the pressure

ratio drops with increasing inlet temperature). Therefore, the engine might be able toreach full load at higher ambient temperatures, while it cant reach full load at lowerambient temperature. Depending on the engine type, the power output at lowambient temperatures might even be lower than the output at high ambient

temperatures. The impact of fuel gas pressure limitations is outlined in Figure 7.

Figure 7: Engine performance and pcd pressure. If the fuel gas pressure is limited, theappropriate line of constant pcd pressure becomes the limit for maximum available power.

EmissionsThe fuel used impacts obviously the constituents in the exhaust gas. If the fuel yields

a high flame temperature, as it is the case with heavier hydrocarbons, as well asHydrogen, Carbon monoxide and some others, it will usually yield a higher amount ofNOx (Hung, 1977). On the other hand, fuels of this type often have a wide

flammability range. Fuels with a low Wobbe Index due to a large amount ofdilutants will yield low flame temperatures, thus low NOx levels, but can causeproblems for start-up and load transients due to a limited flammability range.Another aspect should be considered: The amount of carbon dioxide produced in the

combustion process depends, besides the thermal efficiency of the engine, only onthe amount of carbon in the fuel. While methane has four hydrogen atoms for eachcarbon atom, ethane has only three, and octane only a little over two hydrogenatoms per carbon atom. Thus, burning a methane molecule generates four water

molecules, but only one CO2 molecule. Burning hydrogen causes no CO2 emissionsat all (however, most methods of generating hydrogen do). Burning coal or CO willyield combustion products consisting entirely of CO2. Therefore, typical coal fired

power plants will emit 1000kg/MWh of CO2, oil fired plants yield 800kg/MWh, whilenatural gas fired plants produce 600kg/MWh or less.


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Primary Pretreatment Technologies:

Introduction: Primary pre-treatment technologies represent the first stage in

reducing the amount of contaminants in the fuel gas and typically use simplephysical process operations. The main contaminants removed (or reduced) are water

(albeit contaminated), referred to as condensate and particulates.

Water/condensate KnockoutThe presence of liquid water in gas pipework can have a detrimental effect on the

plant performance. Firstly, accumulation of water reduces the space available for gasflow which means that the pressure loss will be raised, and, secondly, the unstablenature of two-phase flows (i.e. liquid and gas combined) gives rise to oscillations

which in turn means that a steady and controllable operation cannot be achieved.The presence of contaminated water can also lead to deposit formation on the pipewalls which reduces the smoothness and further increases the pressure loss. Hence,the presence of liquid water in gas pipes should be controlled and minimized.

There are three components which can be treated, depending both on the source ofthe gas and application or proposed usage of the treated landfill gas, namely:

- slugs of liquid;- gas-liquid foam; and

- uncondensed water vapour.

The level of complexity (and therefore cost) increases down the list above and thishas determined that many installations rely solely on passive slug catching vessels.

However, some schemes have adopted foam and droplet arresting systems tominimise the effects on engine intake and control systems.The basic principles of each of the treatment options are described below.

Liquid Water Capture

In-line dewatering features are frequently adopted by landfill operators and theseare usually installed within the landfill gas collection network. However, there is

invariably a need to incorporate additional control measures to prevent onwardtransmission of liquid water. In some cases, drains and water traps may be adequatefor the supply gas specification. A further common practice, usually forming the finalelement of dewatering is a knockout drum, often called a condensate knockout pot

(occasionally called a slug catcher). This is located as close as practicable to theinlet to the gas booster. The purpose of the knockout drum is to lower the gasvelocity sufficiently to enable dropout of liquid which may then be drained or

pumped to discharge. Such devices are simple and capable of handling large gasflows (up to 10 000 m3 h-1) and removing over 1 litre min-1 of water (Figure 8).

Foam RemovalAn often adopted refinement to water control systems is the incorporation ofcoalescing (or demisting) meshes in the gas pipes entering and leaving a condensate

knockout drum which collapse entrained foam and prevent carryover. Typically themeshes are woven stainless steel pads which provide a large surface area to trap thefoam and allow it to drain under gravity to the collection drum.

As an alternative (or in addition) to the knockout drum, some equipmentmanufacturers provide cyclones which impart swirl to the incoming gas flow andthereby enhance the rate of liquid removal from the gas stream.

Often several elements (for example, dewatering manifold, knockout drum andsecondary cyclone vessel) are built into a skid-mounted module which is linkeddirectly to the gas booster inlet. Cyclones are reported by manufacturers to be able

to capture 99% of droplets greater than 10 mm1.


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Water and condensates in gas represent possibly the most intractable contaminant

from the gas abstraction perspective, since accumulation in pipework is difficult toeliminate completely and this can cause blockage. In addition, the acidic condensate

can give rise to relatively high rates of corrosion of carbon-steel pipework. Asimplified flowsheet for a primary pre-treatment system is shown in Figure 8.

Figure 8 Primary processing systems


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Vapour Reduction

Raising the pressure of a gas mixture leads to an increase in temperature. Whilstsome of the heat of compression will be dissipated at source1, the delivery gas

stream will inevitably be at a temperature significantly higher than ambient. Thismay give rise to the need to cool the gas to protect control valve seats, prevent

over-stressing of polyethylene (PE) pipework2 and meet other criteria for reliablemetering or consumer safety considerations.For applications where gas conditioning is specified (to reduce the amount of watervapour and lower the dew point), the thermal load on the conditioning unit may be

limited such that a pre-chilling step may be required. Pre-chilling and after-cooling,whilst carried out for different reasons, involve the same basic process, namely heatremoval from the high pressure delivery gas stream.

The amount of heat to be removed will depend upon the specific heat capacity of thegas mixture, the booster exit temperature, the mass flow rate of gas and thespecified final temperature. For typical primary cleanup processes, using for examplea centrifugal gas booster, the heat load is unlikely to require specialist equipment

and a length of 5 to 10 m of corrosion protected steel pipework may be sufficient.

However, some cases where, for example, space is restricted, may benefit fromusing a forced draught cooling stage.It should be noted that in any instance of aftercooling, depending on the condition ofthe gas stream leaving the landfill (in terms of specific moisture content),

compression will reduce the relative humidity which will be reversed on cooling. Thiscan give rise to condensation in the delivery line which can cause problems for theconsumer. It is therefore essential to review and measure the temperature profilealong the pipework, and if necessary, install insulation or lagging (or trace heating)

of the downstream end of the pipe.More complex (and much less widely used) types of gas cooling are available, theseinclude: shell and tube heat exchangers; spray towers and chilled water

recuperators.For some applications, there is a requirement to reduce the moisture content of the

gas stream such that at any point in the delivery pipework the relative saturation isalways well below 100%. In order to achieve this, the gas stream requires

conditioning using a dehumidification process. There are three basic options whichmay be adopted to achieve this function: refrigeration drying; deliquescent bedabsorption; and glycol stripping. The former uses a refrigeration unit to chill the wetgas to around 2C, causing condensation of a proportion of the water vapour. This is

followed by reheating of the cooled gas to between 10C and 15C. Greater levels ofdrying can be achieved by cooling to -18C, although to prevent pipeline icing-up,the gas stream has to be spiked with glycol, which is later removed from the product

gas. Deliquescent dryers involve passing the wet gas stream through a tower orvessel containing a moisture absorbent material (for example, common salt) whichphysically absorbs the moisture. These techniques lead to a pressure loss in thesupply that should be allowed for in the specification of the gas booster and itsoperational settings. In addition, the techniques can add a significant amount to thegas processing costs - refrigeration units have an electrical load (constituting a

relatively large parasitic loss) whereas deliquescent dryers require regulartoppingup of the granular absorbent. The techniques, by their nature, give rise to acontaminated water stream which should be treated or disposed appropriately.

The glycol stripping process is more applicable to larger gas flow rates and involvespassing the wet gas through a counter current contact tower employing for example

triethylene glycol (TEG). Simplified process flowsheets for a refrigeration dryingsystem and a TEG drying system are shown in Figure9 and Figure10, respectively.These may be compared with the basic primary processing arrangement shown in

Figure 4.1.


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Figure 9 Typical Refrigeration-type Gas Conditioning System

Figure10 Simplified Gas Drying using triethylene glycol (TEG)

Particulate FiltrationParticulates can arise in gas stream for a variety of reasons, and if allowed to passdownstream to a supply plant or consumer can give rise to damage and wear of

systems and equipment. Parry (1992) highlighted the need for vigilance whenever

knockout drums are used in systems supplying gas engine generating sets. The issueof concern is bacterial growth in the vessel which leads to particulates that canseriously affect engine operation. Particles can be controlled either by passing the

gas stream through a filter pad (typically made of stainless steel wire) which can alsodouble as a foam coalescing mesh, or alternatively using a cyclone separator.Cyclones are capable of removing particles down to 15 mm (or even 5 mm for a highefficiency cyclone) whereas filter pads are effective down to 2 mm. Both systems are

prone to blockage and therefore require frequent maintenance to removeaccumulated solids.


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Secondary pretreatment technologies

Pre-combustion cleanup of gas trace constituents has no effect on bulk emissions of

CO and NOx and is therefore only of value in reducing aggressive gas constituentsthat either harm the engine or produce unacceptable emission levels. This sectionaddresses those secondary pretreatment options that are available for hydrogen

sulphide, halogenated compounds and siloxanes.

Hydrogen Sulphide Pre-treatmentThere are a number of methods of removing or stripping hydrogen sulphide from gas

streams, involving both wet and dry scrubbing techniques. Wet scrubbing techniquesare usually employed to remove not just hydrogen sulphide but a number ofcomponents.

Hydrogen Sulphide Dry Scrubbing

An early solid chemical treatment for H2S widely employed for coke-oven gas wasthe use of an iron sponge or a material of wood chips impregnated with hydrated

ferric oxide. The H2S within the gas reacts with the iron sponge to form ironsulphide, with cleanup efficiencies up to 99.98%.

Hydrogen Sulphide Wet ScrubbingChemicals used in the wet scrubbing of H2S can be solid or liquid and may be applied

in batch contactor towers or injected directly into the gas pipeline. The by-product ofthe reaction is usually separated and disposed of as a waste. The chemical isconsumed and the absorbent can be regenerated.

Pre-treatment of Halogenated Organic SpeciesA number of processes are available which are capable of treating most halogenatedorganic compounds. These treatments also have an additional effect of scrubbingcarbon dioxide and other trace components. Historically, most of the operational

experience to date has concentrated on the removal of carbon dioxide and theinformation in the following paragraphs reflects this position.

Membrane separation techniquessThe basis of this process is the differential permeability of gases through polymeric

membranes. The separation polymers typically comprise bundles of very largenumbers of hollow fibres arranged in a pressure vessel. When landfill gas is

introduced into the vessel, carbon dioxide passes through whilst methane is heldback. This gives rise to a high pressure methane-rich gas on the outside of the fibresand a lower pressure carbon dioxide enriched gas inside the fibres.

A single stage separation unit cannot provide very complete separation of methaneand carbon dioxide and typically, the low pressure off-gas (carbon dioxide enriched)may contain as much as 12% v/v methane. The product gas contains around 88%

v/v methane. However, multistage separation processes can achieve 98% v/vmethane though pressures required for this operation can be as high as 4 MPa.

Pressure swing processesPressure swing processes rely on the selective adsorption of carbon dioxide on the

surface of special porous solid adsorbents. The adsorption takes place at elevatedpressure and the separation takes place when the pressure on the adsorbent isrelieved - hence the name, Pressure swing adsorption or PSA. Cleanup plant

utilising PSA operate in four steps:-high pressure adsorption;-depressurisation to ambient;-vacuum stripping of carbon dioxide; and


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- repressurisation of product.

There are two basic adsorbent types that have seen some use in the development oflandfill gas cleanup:

-molecular sieves; and-activated carbon beds.

Molecular sieve processesA molecular sieve is essentially a packed bed of granular material (called zeolites)that has special adsorption properties which vary depending on the type of gas.

These materials are characterised by large open structures with numerous openchannels which can effectively adsorb carbon dioxide.The process can only be operated in a batch-wise way, so that an operational

treatment plantrequires multiple cascaded vessels, some of which act to removecarbon dioxide and others (with spent zeolite) operate in a recharge mode. For amolecular sieve to be effective, the gas must be pretreated to remove sulphides(especially hydrogen sulphide), dried to remove water and water vapour and have a

low concentration of nitrogen (nitrogen is not removed by the molecular sieve).

Activated carbon bedsHigh pressure landfill gas is adsorbed on a bed of activated carbon. The bed is thendepressurized and methane and carbon dioxide desorb at different rates allowing a

separation to be made. In order to provide a continuous flow product (since theprocess is batch-wise), a number of vessels are configured such that some areadsorbing whilst others are yielding product in the desorption phase.

System Description at Vimagiri Power Plant

Inlet Separation Skid (SKID #1):

Knock-out Drum: The Knockout Drum consists of an upper section and a lowersection. The upper section contains a vane section and the lower section containsthe liquid collection section.

The upper section includes gas inlet, gas outlet connection, thermal relief valveand vent. The lower section includes connections for level switch, level control andlevel gauge.

Fuel Gas Filter Separators:The filter separator consists of two chambers one theupper chamber and a lower chamber. The upper chamber is made up of a filtersection, held in place with adjustable filter retainers and mounted on the stand offpipes and a mist extractor. It also includes the gas inlet, gas outlet, thermal relief

valve, differential pressure gauge and vent. A screw downs lid closure caps off theupper chamber of the filter separator and allows for ease of filter elementreplacement.The lower chamber includes connections for the redundant high level switches,high-high level switch, level gauge, and a drain.

Drain Tank:mated controls discharge liquids from the Knockout Drum and the Filter

Separators are collected in a drain tank and stored until removed. It includes theliquid inlet, vent, man-way, drain, redundant low-level switches, high-level switch,level gauge and a drain pump.

Dew Point Heaters: The indirect fired heater utilises a water bath, heated by a 'U'tube type firebox, to supply heat to a process coil carrying natural gas, which is alsosubmerged in the water bath.


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Combustion of natural gas, in the fire tube, heats the water bath. This hot water

bath in turn transfers heat to the surface of the process coil, thereby transferringheat to the process gas flowing through the coil.

Pressure Reduction / Regulation Skid (SKID # 2):

A pressure reducing regulator maintains a desired reduced outlet pressure whileproviding the required flow to satisfy a downstream demand. The pressure at whichthe regulator maintains is the outlet pressure setting (set point) of the regulator.Monitoring is over pressure control by containment. When the working pressure

reducing valve ceases to control the pressure, a second regulator installed in series,which has been sensing the downstream pressure, goes into operation to maintainthe downstream pressure slightly higher than normal pressure.

The arrangement of regulation provided is an upstream wide-open monitorarrangement. In this arrangement the both the regulators sense the downstreampressure. Set points are very close to each other. If the worker regulator fails, themonitor assumes control at a slightly higher set point. If the monitor regulator fails

the worker continues to provide control. Any malfunctioning / failure in thecontrolling regulators, shifts the control to the monitor regulator in the same line. Ifthe gas pressure in the running line reaches the shut off set point due to

malfunctioning in both the regulators in the stream, the slam shut will close.

Performance Heater Skid (SKID #3):

Performance Heaters:Performance Heaters are simple heat exchangers in which onemedia is hot water being cooled while the other is a process gas being heated. Hotwater enters the heater at the top. As the moving gas draws heat away from the hot

water, the hot water cools.The heat exchanger consists of two sections one is the tube section and the other

is the shell section. Natural gas enters the shell side of the heat exchanger and hotwater enters the tube side of the exchanger. Connections are provided for waterinlet, gas inlet, gas outlet, water outlet, relief valve and a vent. The upperexchanger and the lower exchanger are provided with a sump in the shell side(gas) section. The sump is provided to catch liquid condensate or slug that would

enter the gas stream should a tube rupture occur.

Fuel Gas Coalescing Filter:The filter separator consists of two chambers. The upper

chamber is made up of a filter section, held in place with adjustable filter retainersand mounted on the stand off pipes. It also includes the gas outlet, redundant high-high level switches, high level switch, level gauge, relief valve, vent, and upperchamber drain. The stand off pipes connects to the lower section via a baffle plate to

direct gas up through theinside of the filter elements. A screw down closure caps offthe top of the filter separator and allows for ease of filter element replacement. The

lower chamber includes a mist extractor and connections for the gas inlet, baffleplate, redundant high level switches, high-high level switch, level gauge, and a lower

chamber drain. Across both chambers are connections for a high differentialpressure switch.

Drain Tank:Automated controls discharge liquids from the Performance Heater andthe Final Filter are collected in a drain tank and stored until removed. It includes theliquid inlet, vent, man-way, drain, redundant low-level switches, high-level switch,level gauge and a drain pump.


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Cold Vent Stack: One cold vent stack is provided near GAILs gas terminal for

venting gas entrapped in pipeline gas during start-up & shutdown operation of theplant. Vents of the knock-out drum is connected to vent header leading to the vent

stack.

Instrumentation:- Pressure and temperature test points.- Flow meter for GT.- Gas chromatograph with multiple stream switch over, capable of measuring

specific gravity, calorific value based on individual constituents of the fuelgas.

The entire gas-conditioning skid will be considered as hazardous area with thefollowing classification:Classification IEC NECGas group (class) IIA D (I)

Zone (division) 2 2

Temperature (class) T2 T2With regard to the atmospheric vents & drains, the areas local to the condensatetank vent and condensate tank discharge will be considered as zone-1 (division-1).

Operation Procedures:Inlet Separation skid (SKID #1)Inlet piping to the knockout drum consists of a manual block valve. The valve can beoperated manually to shut the gas supply to the inlet separation skid .The first stage

of conditioning to the gas stream starts with the gas knockout. The process gasenters the upper section of the gas scrubber through the gas inlet connection and isentrained on the surface of a vane pack as it exits the vessel. Any moisture is

coalesced into droplets then falls into the bottom of the lower chamber. Level controlin the knockout drum is achieved by a pneumatic level control valve.

Liquids discharged from knockout drum are tied to a common drain header, which is

directed to the drain tank. A bypass is provided around the knockout drum and canbe used during maintenance of the knockout drum. A thermal relief valve is providedon the knockout drum to protect the vessel in an event of over pressure due tothermal expansion. A vent is provided with a check valve to vent any gas in the

knockout during maintenance. All relief valve and vent outlets are tied to a commonvent header.A nitrogen purge connection is provided at the inlet of the knockout drum.

In the second stage of fuel gas conditioning, the fuel gas splits off to flow tohorizontal filter separators where two identical 100% capacity horizontal filterseparators are provided on the inlet separation skid, with one as a standby.Gas enters at the inlet of the filter separator, the gas stream then flows around andthrough multiple filter cartridges. The cartridges are designed so mist particles

coalesce into droplets on the outside surface, as the gas flows from the outside tothe inside of each element, and solids are trapped. Any liquid particles that remainin the process gas after flowing through the filter elements are entrained on the

surface of the vane pack. The mist from the gas is trapped by the mist extractor andcoalesces into droplets on the surfaces of the mist extractor vanes. These dropletsflow down the vanes and fall into the reservoir in the lower chamber.

The sump of the lower chamber is divided into two sections .One connection the filtersection of the upper chamber and other connecting the vane pack section of theupper chamber. Level in both of these sections is maintained.


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The solids trapped in the filter elements will gradually increase the pressure drop

across the filter separator and a pressure differential switch monitors this pressuredifferential.

A thermal relief valve is provided on the filter separator to protect the vessel in anevent of over pressure due to thermal expansion. A vent is provided with a check

valve to vent any gas from the filter separator during maintenance.

Automated controls discharge liquids from the knockout drum and the filterseparators are collected in a drain tank.

The fuel gas from the horizontal filter will split off to flow through the dew pointheater. The dew point heater provides additional heat gain to the incoming gas

supply to supplement the performance heater.Two identical 100% capacity dew point heaters are provided, with one as stand by.Each dew point heater has one local BMS panel, which controls the operation of theheater.

The indirect fired heater utilises a water bath, heated by a U tube type firebox, to

supply heat to a process coil carrying natural gas which is also submerged in thewater bath. Combustion of natural gas, in the fire tube heats the water bath. Thishot water bath in turn transfers heat to the surface of the process coil, therebytransferring heat to the process gas flowing through the coil.

A flame scanner (UV type) is mounted on the burner constantly monitors the burnerflame. If for any reason burner flame is lost, the heater will be shutdown.

Pressure reduction/Regulation skid (SKID #2)

The arrangement of regulation provided is an upstream wide-open monitorarrangement. In this arrangement both the worker and monitor regulators sense thedownstream pressure. Set points are very close to each other. If the worker

regulator fails, the monitor assumes control at a slightly higher set point. If themonitor regulator fails the worker continues to provide control.

Pressure reduction/regulation is done for gas turbine and for HRSG.

Performance Heater skid (SKID#3)After pressure regulation skid the fuel gas flows to the performance heater skidwhere the fuel gas gains additional heat. The thermal performance of the powerplant is enhanced by preheating the gas fuel before it is burned in the gas turbine,

with heat taken from the steam cycle. Each gas turbine/HRSG unit has a gas fuelheater. The gas heater or the performance heater is a reverse flow heat exchangerand the heating medium is hot feedwater taken from the outlet of the intermediateeconomiser of the HRSG. The performance heater discharge water flows to the

condenser.The system is configured and operated to maximise the performance benefitavailable from fuel heating. This objective requires that the water leaving theperformance heater en route to the condenser be as cold as possible while the fuelgas to the gas turbine should be as hot as possible (up to its limit).In order to meet

this objective the performance heater is controlled to maintain the target fueltemperature without exceeding a cold end pinch. This avoids returning heated waterinto the condenser, which is inefficient.

The primary function of the separator, is the removal of small contaminants andliquids from a stream of flowing natural gas. The process gas enters the lower

chamber of the filter separator through the gas inlet connection and impacts a vanepack. This is the first step in separating liquids. Mist from the gas is trapped by themist extractor and coalesces into droplets on the surfaces of the mist extractor

vanes. These droplets flow down the vanes and fall into the liquid reservoir in the


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bottom of the vessel. Any liquid particle that remains with the process gas after

flowing into the vane pack then flows through multiple filter cartridges. Thecartridges are designed so mist particles coalesce into droplets on the outside

surface, as the gas flows from the inside to outside of each element. The liquids thatcoalesce and drop out of the gas stream are accumulated in the bottom of the upper

chamber. There are two chambers provided in the filter separator. One is called filterupper chamber and other as lower chamber. Level of both the chambers ismaintained.A thermal relief valve is provided on the filter separator to protect the vessel in an

event of over pressure due to thermal expansion. A vent is provided with a checkvalve to vent any gas from the filter separator during maintenance.An ESD valve is provided at the outlet of the filter separator to shut down gas flow if

gas turbine trip is initiated.

A fail open vent valve is provided to vent the gas in the pipe connecting the filterseparator and the gas turbine. This valve is held closed during operation, when a gas

turbine trip is initiated the solenoid valve de-energises to open the valve.

Automated controls discharge liquids from the performance heater and the filterseparator are collected in a drain tank.

Gas Conditioning skids are controlled from PLC based control panel located in

controlled equipment room in control building. However, each dew point heater isprovided with dedicated microprocessor based BMS panel.

Fuel Gas Conditioning System


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doc - 10 gas conditioning system

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