Simulation and Optimization of Natural Gas Processing Plant

Aspen-HYSYS Simulation of Natural Gas Processing PlantPresented by :- Hari om choudhary

Natural Gas Processing Natural-gas processingis a complex industrialprocessdesigned to clean raw natural gasby separating impurities and various non-methane hydrocarbons and fluids to produce what is known as pipeline quality drynatural gas.Natural-gas processing begins at the well head.

Natural gas produced at the wellhead, which in most cases contains contaminates and natural gas liquids, must be processed and cleaned, before it can be safely delivered to the high-pressure, long-distance pipelines that transport the product to the consumers.

Most natural gas production contains, to varying degrees, small (two to eight carbons) hydrocarbon molecules in addition to methane. Although they exist in a gaseousstate at underground pressures, these molecules will become liquid (condense) at normal atmospheric pressure. Collectively, they are called condensates or natural gas liquids (NGLs).2

The processing of wellhead natural gas into pipeline quality dry natural gas usually involves several processes to remove: (1)oil (2) water (3) elements such as sulfur, helium, and carbon dioxide and (4) natural gas liquids.3

INLET SEPARATORS :-Separators are large drums designed to separate wellstreams into their individual components.3 Principle :- momentum, gravity settling and coalescing .

Vertical :- Vertical separators are preferred when wellstreams have large liquid-to-gas ratios. These separators occupy less floor space than horizontal types and are often found on offshore platforms where floor space is at a premium.

Horizontal :- Horizontal types are preferred when wellstreams have high gas to- oil ratios, when wellstream flow is more or less constant . These separators also have a much greater gas/liquid interface area, which aids in the release of solution gas and in the reduction of foaming .

HORIZONTAL SEPARATOR

Acid gas removal :- Pipeline specifications require removal of the harmful acid gases carbon dioxide (CO2) and hydrogen sulfide (H2S) .

H2S in presence of water is extremely corrosive and can cause premature failure of valves , pipeline and pressure vessels . CO2 is also corrosive and reduces the heating value of natural gas. Removal of CO2 may be required in gas going to cryogenic plants to prevent CO2 solidification.

Gas sweetening processes remove these acid gases and make natural gas marketable and suitable for pipeline distribution.

Amine gas treating process is not a selective and must be designed for total acid-gas removal .Amine gas treating, also known asamine scrubbing,gas sweetening andacid gas removal .

These are some typical amine concentrations, expressed as weight percent of pure amine in the aqueous solution .Monoethanolamine: About 20% for removing H2S and CO2, and about 32% for removing only CO2.Diethanolamine: About 20 to 25% for removing H2S and CO2Methyldiethanolamine: About 30 to 55%% for removing H2S and CO2Diglycolamine: About 50% for removing H2S and CO2 .

MEA is preferred to either DEA and TEA solutions because it is a stronger base and is more reactive than either DEA and TEA .

Reactions of acid gas with MEA absorbing and regenerating :- ABSORBING REACTION :-MEA + H2S MEA HYDROSULFIDE + HEATMEA + H2O + CO2 MEA CARBONATE + HEAT

REGENERATING REACTON :-MEA HYDROSULFIDE + HEAT MEA + H2S MEA CARBONATE + HEAT MEA + H2O + CO2

flash tank 1-Thermosption 2-Kettle

stripper

PACKED TOWER OR TRAY TOWER .Degree of sweeting depend on no of tray and height of packing available in absorber . FLASH TANK = GAS + HCS + AQUEOUS AMINE (density) .REBOILER - HEAT INPUT TO REVERSE REACTION .Reboiler return the heated amine sol and steam to the regenerator tower by same pipe --- thermosption Kettle(different pipe ) .Amine stripper use heat and steam to reverse the chemical rxn . Steam act as a stripping gas to remove co2 and h2s from liquid sol and carries these gases to overhead .Amine cooler reduce lean amine temp other wise high temp would increase the amine vapour pressure and thus increase amine losses to gas .10

The purpose of a glycol dehydration unit is to remove water vapour from natural gas and natural gas liquids.Problems with water in the gas:- If the temperature of pipeline walls or storage tanks decreases below the Tdew of the water vapors present in the gas, the water starts to condense on those cold surfaces, and the following problems can appear.NG in combination with liquid water can form methane hydrate.They plug the valves, the fittings or even pipelines .NG dissolved in condensed water is corrosive, especially when it contains CO2 or H2S.Condensed water in the pipeline causes slug flow and erosion.Water vapor increases the volume and decreases the heating value of the gas.

Dehydration :-

Methane hydrate is a solid in which a large amount of methane is trapped within the crystal structure of water, forming a solid similar to ice.

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Dehydration system :- 1. Direct cooling 2. Compression followed by cooling 3. adsorption4. Absorption Adsorption :- In adsorption dehydration ,the water vapor from the gas is concentrated and held at the surface of the solid desiccant by forces caused by residual valiancy . Absorption :- Hygroscopic liquid desiccant is used in absorption dehydration . glycol have been widely used as effective liquid desiccants.

First two methods does not result in sufficiently low water contents to permit injection into a pipeline .

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The temperature of the lean glycol entering the top tray of the contactor tower should be 10 to 15 F above the temperature of the gas to be treated. If the glycol temperature is too much higher than the gas temperature, the glycol will tend to foam and be carried out of the contactor tower with the gas.

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MERCURY REMOVAL :-History :-The presence of mercury in natural gas became a problem after the catastrophic failure of the aluminum heat exchangers at Skikda in 1973 and the discovery of similar damage at the Groningen Field in the Netherlands.

Mercury is a toxic metal that occurs in natural gas that is harmful to the environment and to chemical processes and transport equipment.In its elemental form, mercury in natural gas amalgamates (forms an alloy) with the aluminum in heat exchangers, eventually causing physical failure.

Regenerative adsorbent for mercury removal :-UOP HgSIV adsorbents are regenerative molecular sieve products that contain silver on the outside surface of the molecular sieve pellet or bead. Mercury from the process fluid (either gas or liquid) amalgamates with the silver and a mercury-free dry process fluid is obtained at the bed outlet

The mercury removal function can be easily added to the dehydrator performance by replacing some of the molecular sieve with a mercury removal adsorbent.

convert the dehydrator to the dual function of water and mercury removal by replacing some of the dehydration molecular sieve with HgSIV adsorbent14

Same as another regenerative adsorption application such as drying. By replacing some of the drying adsorbent with a dual function water and mercury removal adsorbent, both water and mercury are removed in the dehydrator. the silver on the surface and readily available to the mercury, the mercury atom does not have to diffuse through the pore structure . When the adsorbent is heated to the normal dehydrator regeneration temperature, the mercury is released from the silver and it leaves with the spent regeneration gas .The plus side of this approach is no additional equipment cost, no additional pressure drop, and the possibility of recovering most of the mercury as a separate mercury stream..15

Nitrogen lowers the heating value of the gas and makes it unsaleable to most pipelines. Natural gas will be accepted for transport by pipeline only if it contains less than a specified amount of nitrogen, typically somewhere between 4% and 6%.

High flow-rate applications:-cryogenicprocessing is the norm.This is adistillationprocess which utilizes the different volatilities ofmethane(boiling pointof 161.6C) andnitrogen(boiling point of 195.69C) to achieve separation. In this process, a system of compression and distillation columns drastically reduces the temperature of the gas mixture to a point where methane is liquified and the nitrogen is not.

For smaller volumes of gas:- a system utilizingPressure Swing Adsorption(PSA) is a more typical method of separation. In PSA:- methane and nitrogen can be separated by using an adsorbent with an aperture size very close to the molecular diameter of the larger species, in this case methane (3.8angstroms). This means nitrogen (3.6angstroms) is able to diffuse through the adsorbent, filling adsorption sites, whilst methane is not.

NITROGEN REMOVAL:-

to avoid unnecessary flaring and associated air pollution.

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NGL RECOVERY :- Recovery of NGL for hydrocarbon dew point control in natural gas stream (to avoid unsafe formation of a liquid phase during transport ) . natural gas is processed to remove the heavier hydrocarbon [ethane , propane and natural gasoline( condensate) ] liquids from the natural gas stream .

NITROGEN REMOVAL UNIT

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Simulation of gas processing plant

Sweet natural gas :- feed 20 MMSCFD pressure 1010 Psig.

At thehigh temperature, theglycolloses its ability to hold water. As countercurrent absorption in contactor is directly dependent on the quality of the lean TEG fed to the contactor, higher efficiency of water removal ( 99%) is one of the main areas of concern in optimization of this process.

The reboiler temperature influences the overhead water content by changing the purity of the lean glycol. Glycol purities of98.0, 98.5, and 98.8 wt % are obtained at 360, 380, and 400 oF, respectively, at one atmosphere pressure.

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The higher the gas temperature, the more water it will contain in vapour form.If the temperature of the wet natural gas is around 140F or above, the natural gas does not want to give up the water vapour to the glycol. On the other hand, if the natural gas temperature is 40F or below, the glycol becomes viscous and does not want to pick-up the water vapour. Therefore, dehydration will take place at temperatures between 50 to 130F. The best results will be obtained between 80 and 110F .

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Increasing the number of trays allows the gas to approach equilibrium with the lean glycol at a lower glycol circulation rate.

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Conclusion :-

Natural gas processing step is explained and the discussed the processing of every step.A simulation model of natural gas processing plant is developed using the process simulator HYSYS.The design review involved a review of the TEG dehydration systems generally and in comparison to the proposed design.At the end we design a mercury removal plant in natural gas processing for a particular flow rate and condition.

References :- https://www.google.co.in/search?sourceid=chrome-psyapi2&ion=1&espv=2&ie=UTF-8&q=natural%20gas%20process&oq=natural%20ga&aqs=chrome.0.69i59l3j0j69i60j0.19365j0j7

https://www.youtube.com/watch?v=sPDvpZiIX7o

Dehydration of Natural Gasby Prof. Jon Steiner Gudmundsson, Norwegian University of Science and Technology

https://en.wikipedia.org/wiki/Amine_gas_treating

Aspen-HYSYS Simulation of Natural Gas Processing Plant Partho S. Roy* and Ruhul Amin M. Department of Chemical Engineering, Bangladesh University of Engineering & Technology (BUET), Dhaka-1000, Bangladesh