GAS PLANT IMP PROCESS

• Dehydration• Associated oil stabilization• Carbon dioxide or nitrogen recovery

for enhanced oil recovery (EOR).• Upgrading subquality gas• Helium recovery• Liquefaction.

Typical Layout

Gas & liquid from well

Field Processing& Comp

Inlet Receiving & Comp

WaterDisposal

Elemental Sulfur

Sulfur Recovery

So2 + Co2

Gas Treating

LPG

Liquefaction

Dehydration

N2 Rejection

HC Recovery

He Rejection

LNG

SALES GAS

NGL

Sales gas

SALES GAS FROM ONGC

Outlet Comp

LPG, PROPANE,PENTANE, SBP

Field Operations and InletCompression

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ACID GASES REMOVAL PROCESS

Acid gases present in Natural gas

• CO2

• H2S

• Gas with out CO2 and H2S is called“ Sweet ” Otherwise “ Sour ”

• Both gases are undesirable because they causeCorrosionReduce Heating ValueReduce sale Value

Milligramsper CubicMeter*

Physiological Effects

0.18 Obvious and unpleasant odor

14.41 Acceptable ceiling concentration permitted by Federal OSHA standards.

72.07 Acceptable maximum peak above the OSHA

144.14 Coughing, eye irritation, loss of sense of smell after 3 to 15 minutes. Altered respiration, pain ineyes, and drowsiness after 15 to 30 minutes, followed by throat irritation after one hour.Prolonged exposure results in a gradual increase in the severity of these symptoms.

288.06 Kills sense of smell rapidly, burns eyes and throat.

720.49 Dizziness, loss of sense of reasoning and balance. Breathing problems in a few minutes. Victimsneed prompt artificial resuscitation.

1008.55 Unconscious quickly. Breathing will stop and deaths will result if not rescued promptly. Artificialresuscitation is needed.

1440.98+ Unconsciousness at once. Permanent brain damage or death may result unless rescued promptlyand given artificial resuscitation.

*Based on 1 percent hydrogen sulfide = 629.77 gr/100 SCF at 14.696 psia and 59°59°F, or 101.325 kPa and 1515°°C.

H2S Presence and its effect

SOLID BED PROCESSES

Iron Sponge Process

• The iron sponge process utilizes the chemical reaction of ferricoxide with H2S to sweeten gas streams. This process iseconomically applied to gases containing small amounts ofH2S. This process does not remove carbon dioxide. Thereaction of hydrated colloidal iron oxide and H2S producesiron sulfide and water as follows:

• Operating Conditions:• Temp < 49°C + Presence of Water.• Temp > 49°C (pH 8 - 10 shall be maintained caustic soda, soda

ash, lime, or ammonia with the water. Figure 2 (Iron oxide acidgas treating unit) shows a vessel for the iron sponge process.

Figure 1

• The ferric sulfide can be oxidized with air to producesulfur and regenerate the hydrated ferric oxide.

• Typically, after ten cycles the bed must be removed fromthe vessel and replaced with a new bed.

• The reactions for oxygen regeneration are as follows:

AMINE PROCESSES

• Several processes have been developed using thebasic action of various amines. These amines can becategorized by the number of organic groups bondedto the central nitrogen atom, as primary, secondary ortertiary. For example:

A typical amine system is shown in Figure 3 (Gassweetening process flow schematic of amine sweetening).

Figure 2

• The most common amine processes aremonoethanolamine (MEA) and diethanolamine(DEA). Both processes will remove CO2 and H2Sto pipeline specifications. Among the newerprocesses, which have been developed ismethyldietha-nolamine (MDEA). It can be used forselective removal of H2S in the presence ofCO2 and significantly reduces treating costs whenCO2 reduction is not necessary.

SEVERAL PROCESS

Numerous processes have been developed for acid gasremoval and gas sweetening based on a variety ofchemical and physical principles. These processes(Table 2) can be categorized by the principles used inthe process to separate the acid gas from the othernatural gas components. The list, although notcomplete, represents many of the common availablecommercial processes. Table 3 shows the gases thatare removed by the different processes.Table 4 illustrates the process capabilities of some ofthe processors for gas treating.

Sulfinol

Table 2: Acid Gas Removal Processes

Continued

Table 3: Gases Removed by Various Processes

Continued

Figures 1 (H2S removal -no CO2 present),

Figure 2 (CO2 removal -no H2S present) ,

Figure 3 (Removal of H2S and CO2.) ,

and Figure 4 Selective removal -H2S in presenceof CO2.) can be used as screening tools to make aninitial selection of potential process choices

Back to Layout Other Process

SULFA-TREAT PROCESS

• This process is similar to the iron spongeprocess utilizing the chemical reaction offerric oxide with H2S to sweeten gasstreams. This process is economicallyapplied to gases containing small amountsof H2S. Carbon dioxide is not removed inthe process.

• Sulfa-Treat utilizes a proprietary iron oxideco-product mixed with inert powder to forma porous bed. Sour gas flows through thebed and forms a bed primarily of pyrite. Thepowder has a bulk density of 70 lbs/ft3andranges from 4 mesh to 30 mesh.

• The reaction works better with saturatedgas and at elevated temperature up to54.4°C (130°F). No minimum moisture orpH level is required. The amount of bedvolume required increases as the velocityincreases and as the bed height decreases.

Operation of the system below 4.4°C(40°F) is not recommended.

• The beds are not regenerated and must bereplaced when the bed is spent.

MOLECULAR SIEVE PROCESS

• Molecular sieve processes use syntheticallymanufactured crystalline solids in a dry bed toremove gas impurities. The crystallinestructure of the solids provides a very porousmaterial having uniform pore size. Within thepores the crystalline structure creates a largenumber of localized polar charges called

active sites. Polar gas molecules such as H2Sand water vapor, which enter the pores, formweak ionic bonds at the active sites. Non-polarmolecules such as paraffin hydrocarbons willnot bond to the active sites.

• Molecular sieves are available with a variety of pore sizes.A molecular sieve should be selected with a pore size thatwill admit H2S and water while preventing heavyhydrocarbons and aromatic compounds from entering thepores. Carbon dioxide molecules are about the same size asH2S molecules, but are non-polar. Thus, CO2 will enter thepores but will not bond to the active sites. Small quantitiesof CO2 will be removed by becoming trapped in the poresby bonded H2S or H2O molecules blocking the pores. Moreimportantly, CO2 will obstruct the access of H2S and H2Oto the active sites, decreasing the overall effectiveness ofthe molecular sieve. Beds must be sized to remove all H2Oand provide for interference from other molecules in order

to remove all H2S.

• The adsorption process usually occurs at moderatepressure. Ionic bonds tend to achieve an optimumperformance near 3100 kPa (450 psig), but thesystem can be used for a wide range of pressures.

• The molecular sieve bed is regenerated by flowinghot sweet gas through the bed. The hot strippinggas breaks the ionic bonds and removes the H2Sand H2O from the sieve. Typical regenerationtemperatures are in the range of 150°C to 200°C(300°F to 400°F).

• Molecular sieve beds can suffer chemical andmechanical degradation. Care should be taken tominimize mechanical damage to the solid crystals asthis may decrease the bed's effectiveness. The maincauses of mechanical damage are the sudden pressureand/or temperature changes that may occur whenswitching from adsorption to regeneration cycles.Proper instrumentation can significantly extend bedlife.

• Molecular sieves are generally limited to small gasstreams operating at moderate pressures. Due to theseoperating limitations, molecular sieve units have seenlimited use for gas sweetening operations. They aregenerally used for polishing applications followingone of the other processes.

ZINC OXIDE PROCESS

• This process is similar to the iron sponge process inthe type of equipment used. The zinc oxide processuses a solid bed of granular zinc oxide to react withthe H2S to form zinc sulfide and water as shownbelow.

• The rate of reaction is controlled by the diffusion process,as the sulfide ion must first diffuse to the surface of thezinc oxide to react. Temperatures above 120°C (250°F)increase the diffusion rate and are normally used topromote the reaction rate. The strong dependence ondiffusion means that other variables such as pressure andgas velocity have little effect on the reaction

• Zinc oxide is usually contained in long thin bedsto lessen the chances of channeling. Pressure dropthrough the beds is low. Bed life is a function ofgas sulfide content and can vary from six monthsto over ten years. The beds are often used in seriesto increase the level of saturation prior to changeout of the catalyst. The spent bed is discharged bygravity flow through the bottom of the vessel. Theprocess has seen decreasing use due to increasingdisposal problems with the spent bed, which isclassified as a heavy metal salt.

CHEMICAL SOLVENT PROCESSES

• Chemical solvent processes use an aqueous solution ofa weak base to chemically react with and absorb theacid gases in the natural gas stream. The absorptiondriving force is a result of the partial pressuredifferential between the gas and the liquid phases. Thereactions involved are reversible by changing thesystem temperature or pressure, or both. Therefore, theaqueous base solution can be regenerated andcirculated in a continuous cycle. The majority ofchemical solvent processes utilize either an amine orcarbonate solution.

MONOETHANOLAMINE SYSTEMS (MEA)

• Monoethanolamine (MEA) is a primary amine, which hashad widespread use as a gas sweetening agent. Thisprocess is well proven, can meet pipeline specifications,and has more design/operating data available than anyother system. MEA is a stable compound and in theabsence of other chemicals suffers no degradation ordecomposition at temperatures up to its normal boilingpoint.

• MEA reacts with CO2 and H2S as follows:

• These reactions are reversible by changing the systemtemperature. The reactions with CO2 and H2S shown aboveare reversed in the stripping column by heating the rich MEAto approximately 118°C at 69 kPa (245°F at 10 psig). The acidgases evolve into the vapor and are removed from the stilloverhead. Thus the MEA is regenerated. A disadvantage ofMEA is that it also reacts with carbonyl sulfide (COS) andcarbon disulfide (CS2) to form heat stable salts, which cannotbe regenerated at normal stripping column temperatures. At

temperatures above 118°C (245°F) a side reaction withCO2 exists which produces oxazolidone-2, a heat stable salt,which consumes MEA from the process

Diethanolamine Systems (DEA)

• Diethanolamine (DEA) is a secondary amine also usedto treat natural gas to pipeline specifications. As asecondary amine, DEA is less alkaline than MEA.DEA systems do suffer the same corrosion problems,but not as severely as those using MEA. Solutionstrengths are typically from 25 to 35 percent DEA byweight in water.

• DEA reacts with CO2 and H2S as follows

DIGLYCOLAMINE® SYSTEMS (DGA)

• The Fluor Econamine Process uses diglycolamine® (DGA)to treat natural gas. The active DGA reagent is 2-(2-aminoethoxy) ethanol, which is a primary amine as follows:

• The reactions of DGA with acid gases are the same asthose for MEA. Unlike MEA, degradation products fromreactions with COS and CS2can be regenerated.

• DGA systems typically circulate a solution of 50to 70 percent DGA by weight in water. At thesesolution strengths and a loading of up to 0.3moles of acid gas per mole of DGA, corrosion inDGA systems is slightly less than in MEAsystems. The advantages of a DGA system arethat the low vapor pressure decreases aminelosses, and the high solution strength permitslower circulation rates.

DIISOPROPANOLAMINE SYSTEMS (DIPA)

• Diisopropanolamine (DIPA) is a secondary amineused in the Shell "ADIP®" process to sweetennatural gas.

• DIPA systems are similar to DEA systems but offerthe following advantages:

• Carbonyl sulfide (COS) can be removed and theDIPA solution regenerated easily

• The system is generally non-corrosive• Lower energy consumption

METHYLDIETHANOLAMINE SYSTEMS (MDEA)

• Methyldiethanolamine is a tertiary amine, which likethe other amines, is used to treat acid gas streams. Themajor advantage, which MDEA offers over otheramine processes, is its selectivity for H2S in thepresence of CO2. If the gas is contacted at pressuresranging from 5500 to 6900 kPa (800 to 1000 psig),H2S levels can be reduced to the very lowconcentrations required by pipelines, while at the same

present flowstime 40 to 60 percent of the CO2

through the contactor, unreacted.

• In cases where a high CO2/H2S ratio is present,MDEA can be used to improve the quality of theacid gas stream to a Claus recovery plant, but thehigher CO2 content of the treated residue gasmust be tolerated.

• Solution strengths typically range from 40 to 50percent MDEA by weight. Acid gas loadingvaries from 0.2 to 0.4 or more moles of acid gasper mole of MDEA depending on supplier.MDEA has a molecular weight of 119. MDEAsolution makeup is dependent upon the supplier.It can be adjusted to optimize treatment for aparticular gas inlet composition.

• Higher allowable MDEA concentration and acidgas loading results in reduced circulation flowrates. Significant capital savings are realized dueto reduced pump and regeneration requirements.MDEA has a lower heat requirement due to itslow heat of regeneration. In some applications,energy requirements for gas treating can bereduced as much as 75 percent by changing fromDEA to MDEA.

INHIBITED AMINE SYSTEMS

• These processes use standard amines that have beencombined with special inhibiting agents which minimizecorrosion. This allows higher solution concentrationsand higher acid gas loadings, thus reducing requiredcirculation rates and energy requirements.

CARBONATE PROCESSES

• Hot Potassium Carbonate Systems• Carbonate processes generally utilize hot potassium

carbonate to remove CO2 and H2S. As a generalrule, this process should be considered when thepartial pressure of the acid gas is 138 kPa (abs) (20psia) or greater. It is not recommended for lowpressure absorption, or high pressure absorption oflow concentration acid gas.

• The main reactions involved in this process are:

• These reactions are reversible based on the partialpressures of the acid gases. Note that potassiumbicarbonate (KHCO3) solutions are not readily regenerablein the absence of CO2, so that these processes are onlyemployed for H2S removal when quantities of CO2 arepresent. Potassium carbonate also reacts reversibly withCOS and CS2.

Figure4 (Gas sweetening flow schematic of a hotcarbonate process) shows a typical hot carbonatesystem for gas treating.

Figure 4

PHYSICAL SOLVENT PROCESSES

• Physical solvent systems are very similar to chemicalsolvent systems but are based on the gas solubilitywithin a solvent instead of a chemical reaction. Thepartial pressure of the acid gases and the systemtemperature both affect the acid gas solubility. Higheracid gas partial pressures increase the acid gassolubility. Low temperatures have a similar effect, but,in general, temperature is not as critical as pressure.

• Various organic solvents are used to absorb the acid gasesbased on partial pressures. Regeneration of the solvent isaccomplished by flashing to lower pressures and/orstripping with solvent vapor or inert gas. Some solventscan be regenerated by flashing only and require no heat.Other solvents require stripping and some heat, buttypically the heat requirements are small compared tochemical solvents.

• Physical solvent processes have a high affinity for heavyhydrocarbons. If the natural gas stream is rich inC3+ hydrocarbons, then the use of a physical solventprocess may result in a significant loss of the heaviermole weight hydrocarbons. These hydrocarbons are lostbecause they are released from the solvent with the acidgases and cannot be economically recovered.

• Under the following circumstances physical solventprocesses should be considered for gas sweetening:

• The partial pressure of the acid gases in thefeed is 345 kPa (50 psi) or higher

• The concentration of heavyhydrocarbons inthe feed is low

• Only bulk removal of acidgases is required

• Selective H2S removal is required

A physical solvent process is shown inFigure 5 (Typical flow schematic of a physicalsolvent process).

Figure 5

• The sour gas contacts the solvent usingcountercurrent flow in the absorber. Richsolvent from the absorber bottom is flashed instages to near atmospheric pressure. This causesthe acid gas partial pressures to decrease, andthe acid gases evolve to the vapor phase and areremoved. The regenerated solvent is thenpumped back to the absorber.

FLUOR SOLVENT PROCESS

• The Fluor Solvent process uses propylene carbonate asa physical solvent to remove CO2 and H2S.

• Propylene carbonate also removes C3+ hydrocarbons,COS, SO2, CS2 and H2O from the natural gas stream.

• Thus, in one step the natural gas can be sweetenedand dehydrated to pipeline quality.

• This process is used for bulk removal of CO2 and isnot used to treat to less than 3 percent CO2 as may berequired for pipeline quality gas.

SULFINOL® PROCESS

• The Sulfinol®process, developed and licensed byShell, employs both a chemical and a physicalsolvent for the removal of H2S, CO2, mercaptans,and COS. The Sulfinol®solution is a mixture oftetrahydrothiophene dioxide (Sulfolane®), which isthe physical solvent; a secondary amine,diisopropanolamine (DIPA); and water. DIPA,previously discussed, is the chemical solvent.Typical solution concentrations range from 25 to 40percent Sulfolane®, 40 to 55 percent DIPA, and 20to 30 percent water, depending on the conditions andcomposition of the gas being treated.

• The presence of the physical solvent,Sulfolane®, allows higher acid gas loadingscompared to systems based on amine only.Typical loadings are 1.5 moles of acid gas permole of Sulfinol® solution. Higher acid gasloadings, together with a lower energy ofregeneration, can result in lower capital andenergy costs per unit of acid gas removed ascompared to the ethanolamine processes.

SELEXOL® PROCESS

• Selexol® is a process using the dimethylether ofpolyethylene glycol as a solvent. It was developed by AlliedChemical Company and is licensed by the Norton Company.This process is selective toward removing sulfur compounds.Levels of CO2 can be reduced by approximately 85 percent.This process may be used economically when there are highacid gas partial pressures and an absence of heavy ends inthe gas. The Selexol® process will not normally remove

enough CO2 to meet pipeline gas requirements. DIPA canbe added to the solution to remove CO2 down to pipelinespecifications. This process also removes water to less than0.11 g/stdm3 (7 lb/MMSCF). This system then functionsmuch like the Sulfinol® process discussed earlier. Theaddition of DIPA increases the relatively low stripper heatduty.

RECTISOL PROCESS

• The German Lurgi Company and Linde A. G. developedthe Rectisol process to use methanol to sweeten naturalgas. Due to the high vapor pressure of methanol thisprocess is usually operated at temperatures of -34°C to -74°C (30°F to -100°F). It has been applied for thepurification of gas for LNG plants and in coal gasificationplants, but is not commonly used to treat natural gasstreams

DIRECT CONVERSION PROCESSES

• Direct conversion processes use chemical reactions tooxidize H2S and produce elemental sulfur. These processesare generally based either on the reaction of H2S andO2 or H2S and SO2. Both reactions yield water andelemental sulfur. These processes are licensed and involvespecialized catalysts and/or solvents.

STRETFORD PROCESS

• An example of a process using O2 to oxidize H2S is theStretford process, which is licensed by the British GasCorporation. In this process the gas stream is washed withan aqueous solution of sodium carbonate, sodium vanadate

and anthraquinone disulfonic acid. Figure 6 (StretfordProcess) shows a simplified diagram of the process.

IFP PROCESS

• The Institute Francais du Petrole has developed aprocess for reacting H2S with SO2 to produce waterand sulfur. The overall reaction is:

• This process involves mixing the H2S andSO2 gases and then contacting them with aliquid catalyst in a packed tower. Elementalsulfur is recovered in the bottom of the tower. Aportion of this must be burned to produce theSO2 required to remove the H2S. The mostimportant variable is the ratio of H2S to SO2 inthe feed. This is controlled by analyzerequipment to maintain the system performance.

LO-CAT®/SULFEROX®

• Developed by ARI Technologies and Shell Development,respectively, these processes employ high iron concentrationreduction-oxidation technology for the selective removal ofH2S to less than 4 ppm in both low and high pressure gasstreams. The acid gas stream is contacted with the solutionwhere H2S reacts with and reduces the chelated-iron andproduces elemental sulfur. The iron is then regenerated byreaction with the oxygen in air. The reactions involved areexothermic:

Figure 8 (LO-CAT) illustrates the process designfor the LO-CAT® process.

Figure 8

Figure 9 (Example SulFerox®System) illustratesthe process design for the SulFerox® process.

Figure 9

• The SulFerox® process uses the patented pipelinecontactor with co-current flow to minimize sulfurplugging. The system has a high turndowncapability.

• These units are relatively small per unit of acid gas treated.The technology of these processes has many potentialapplications such as:

Treatment of sour produced or recycled CO2

Remote, single well streamsTail Gas treatmentOffshore installations

Sulfur Recovery

• The Claus process is used to treat gas streamscontaining high concentrations of H2S.

(Typical flow diagram of a two-stage Claus processplant) shows a simplified process flow diagram of theClaus process.

• The first stage of the process converts H2S tosulfur dioxide and to sulfur by burning the acidgas stream with air in the reaction furnace. Thisprovides SO2 for the next phase of thereaction. Multiple reactors are provided toachieve a more complete conversion of theH2S. Condensers are provided after eachreactor to condense the sulfur vapor andseparate it from the main stream. Conversionefficiencies of 94 to 95 percent can be attainedwith two catalytic stages while up to 97 percentconversion can be attained with three catalyticstages. As dictated by environmental concernsthe effluent gas is either vented, incinerated orsent to a "tail gas treating unit." Back to Layout

Tail Gas Treatment from SulfurRecovery Plant (SCOT)

• Using Cobalt-Molybdenum on Alumina (Inside Reactor) as Catalyst the Sulfur

compounds including So2, CoS, CS2 are reduced to H2S and Water.

•Further application of MDEA or DIPA, the H2S is stripped off from the gases leaving CO2and can be further used as lean mixture in Claus Unit Back To Layout

Removal of CO2

• Removal of CO2 to meet pipeline qualityspecifications can be accomplished with anamine-based system since the acid gas fromthe stripper can be vented (assuming levels ofH2S in the gas being treated are very low).

• Removal of CO2 with gas permeation may beattractive for low volume gas streams inremote areas where the loss of methane is notcritical. Permeation systems with a secondstage recycle may be competitive with aminesystems.

1.Natural, associated, or tail gas usually contains water, in liquidand/or vapor form, at source and/or as a result of sweetening withan aqueous solution.

2.Formation of Solid hydrates and plug valves or even pipelines.2. Water can condense , causing slug flow, erosion and corrosion.

NATURAL GAS DEHYDRATION

3. As pipeline spec says maxi water content of 7 lb H2O perMMscf.

Methods of Dehydration:• liquid desiccant (glycol) dehydration,• solid desiccant dehydration, and• refrigeration (i.e., cooling the gas).

GLYCOL DEHYDRATION

Among the different gas drying processes, absorption isthe most common technique, where the water vapor in thegas stream becomes absorbed in a liquid solvent stream.Glycols are the most widely used absorption liquids as theyapproximate the properties that meet commercial applicationcriteria.

Several glycols have been found suitable for commercialapplication.

Description Boiling Point ºF

Monoethylene glycol (MEG) 50

Diethylene glycol (DEG) 315 to 340

Triethylene glycol (TEG) 340 to 400

Tetraethylene glycol (TREG) 400 to 430

Types of Glycols

TEG is by far the most common liquid desiccant used in naturalgas dehydration. It exhibits most of the desirable criteria ofcommercial suitability listed here (Manning and Thompson,1991; Hubbard, 1993).1. TEG is regenerated more easily to a concentration of 98–99%2. Vaporization losses are lower than compared to MEG & DEG3. CAPEX and OPEX is Less

Figure 3. Simplified flow diagram for TEG dehydration(Manning and Thompson, 1991).

Figure 4. Typical flow diagram for a glycol dehydration unit(NATCO, 1984). Back to layout Other Process

SOLID DESICCANT DEHYDRATION

Solid desiccant dehydration systems work on the principle ofadsorption.

Solid desiccant dehydrators are typically more effective than glycoldehydrators, as they can dry a gas to less than 0.1 ppmV (0.05lb/MMcf), but not suitable for bulk removal of water

The glycol unit would reduce the water content to around 60 ppmV,which would help reduce the mass of solid desiccant necessary forfinal drying.

The most common commercial desiccants used in dry beddehydrators are silica gel (i.e., Sorbead), molecular sieves,and activated alumina.Silica gel is a widely used desiccant for gas & liquiddehydration and HC recovery. It is characterized by thefollowing.• Easily regenerated than molecular sieves.• Has high water capacity, where it can adsorb up to 45% ofits own weight in water.

• Costs less than molecular sieve.• Capable of dew points to −1400F.

Natural Gas Liquids Fractions

• If a natural gas contains a relatively large fraction ofhydrocarbons other than methane (i.e condensategas or associated gas), separation of these heaviercomponents are needed to avoid formation of liquidphase during transport.

• Separation can be achieved usually by lowering gastemperature, absorption and adsorption.

• From figure 7.15, it is representing normal boilingpoint of natural gas fractions. Separation by loweringtemperature needs to get the temperature belowthis normal boiling point, which is at 1 atm.

The following liquid fractions can be obtainedin succession by lowering the temperature:• Natural gasoline or condensate which is a light

gasoline representing mainly the C5+ fraction.• LPG fraction which includes propane and butanes

(normal butane and isobutane)• NGL fraction which contains C2, C3, C4 (iso and

normal), natural gasoline – Process goal is not toseparate between natural gasoline and LPG.

• LNG-- by lowering the temperature to about -160oCat 1 atm. Mainly contains methane and generallycontains ethane.

Cold Residue Process forMaximizing the Recovery of Ethane

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NITROGEN RECOVERY• There are three important Methods:

• Cryogenic Distillation (for Nitrogen Rates)– Adsorption & Membrane Separation (Low Rates)

NRU by Two Column CryogenicDistillation Method

NRU by Pressure Swing AdsorptionMethod

NRU by Membrane Separation

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NRU for EOR (Simple Layout)

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Helium Composition in NG

•Helium is typical difficult diluent in NG unless Nitrogen Rejection is used

•Presently we have Darwin Plant in Australia and other Plant in Qatar are verybig Plants in the World. BOC has recently commissioned one Plant in USA

Recovery Plant Layout

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Ultimately type of Gas PlantProcessing depends on

• Composition of Crude• Offshore or Onshore• Specifications of the Sales Gas• Environmental Regulations• Feasibility and Economics