The document summarizes the key steps in natural gas processing:
1) Natural gas produced at the wellhead contains contaminants and must be processed before transport via pipelines. Inlet separators separate the wellstream into components using gravity, momentum and coalescing.
2) Acid gases like H2S and CO2 are removed using amine gas treating which uses aqueous amines like MEA in absorption and regeneration reactions.
3) Glycol dehydration units use hygroscopic glycols like triethylene glycol to absorb water vapor which can cause issues if condensed in pipelines.
4) Mercury is removed using regenerative molecular sieves containing silver which amalgamates with mercury.
5) Nitrogen is separated
ALL ABOUT NATURAL GAS : DEFINITION,FORMATION,PROPERTIES,COMPOSITION,PHASE BEHAVIOR ,CONDITIONING"DEHYDRATION ,SWETENING" AND FINAL PROCESSING TO END USER PRODUCTS
Processing of Hydrogen Sulfide & Carbon Dioxide From Natural Gas StreamsMohamed Almoalem
This poster was presented in GPA (Gas Processors Association) 23rd technical conference in November 2015. It is the outcome of an individual research that was done voluntarily by me during my internship in Tatweer Petroleum.
We ensure safe execution of all natural gas dehydration processes. Formulated solvents are used for acid gas treatment to achieve proper bio gas processing. If you getting more information about that visit on to http://www.deltapurification.com/ or call (306)-352-6132
ALL ABOUT NATURAL GAS : DEFINITION,FORMATION,PROPERTIES,COMPOSITION,PHASE BEHAVIOR ,CONDITIONING"DEHYDRATION ,SWETENING" AND FINAL PROCESSING TO END USER PRODUCTS
Processing of Hydrogen Sulfide & Carbon Dioxide From Natural Gas StreamsMohamed Almoalem
This poster was presented in GPA (Gas Processors Association) 23rd technical conference in November 2015. It is the outcome of an individual research that was done voluntarily by me during my internship in Tatweer Petroleum.
We ensure safe execution of all natural gas dehydration processes. Formulated solvents are used for acid gas treatment to achieve proper bio gas processing. If you getting more information about that visit on to http://www.deltapurification.com/ or call (306)-352-6132
Sweetening and sulfur recovery of sour associated gas in the middle eastFrames
Effective and efficient removal of hydrogen sulfide (H2S) is an essential step when sweetening gas for downstream processes. By simultaneously turning the captured hydrogen sulfide into elemental sulfur, a Frames THIOPAQ O&G system improves gas value, while creating a saleable chemical widely sought after in the agricultural and bulk chemical industry.
Application: Chemical agents employed in natural gas processing include drilling fluid additives, methanol injection for freeze protection, glycol injection for hydrate inhibition, produced water treatment chemicals, foam and corrosion inhibitors, de-emulsifiers,and drag reduction agents. Chemicals are frequently administered by way of chemical injection skids.
Challenges: Level monitoring controls chemical inventory
and determines when the tanks require filling.The careful
selection and application of level controls to chemical injection systems can effectively protect against tanks running out of chemicals or overfilling.
H2 S and SO2 removal and possible valorizationSerge Vigneron
H2S is a common pollutant in gas and air. This presentation is a review of different techniques to remove H2S ,and possible ways of valorization to sulfuric acid via SO2.
Natural Gas (from a natural reservoir or associated to a crude production) can contain acid gas (H2S and/or CO2)..
The Gas Sweetening Process aims to remove part or all of the acid gas.
Episode 3 : Production of Synthesis Gas by Steam Methane ReformingSAJJAD KHUDHUR ABBAS
Episode 3 : Production of Synthesis Gas by Steam Methane Reforming
History of Synthesis Gas
In 1780, Felice Fontana discovered that combustible gas develops if water vapor is passed over carbon at temperatures over 500 °C. This CO and H2 containing gas was called water gas and mainly used for lighting purposes in the19th century.
As of the beginning of the 20th century, H2/CO-mixtures were used for syntheses of hydrocarbons and then, as a consequence, also called synthesis gas.
Haber and Bosch discovered the synthesis of ammonia from H2 and N2 in 1910 and the first industrial ammonia synthesis plant was commissioned in 1913.
The production of liquid hydrocarbons and oxygenates from syngas conversion over iron catalysts was discovered in 1923 by Fischer and Tropsch.
Much of the syngas conversion processes were being developed in Germany during the first and second world wars at a time when natural resources were becoming scare and alternative routes for hydrogen production, ammonia synthesis, and transportation fuels were a necessity.
In 1943/44, this was applied for large-scale production of artificial fuels from synthesis gas in Germany.
Natural gas processing: Production of LPG Asma-ul Husna
This is a presentation on a process designed for a natural gas processing plant that can use NGL and condensate to produce LPG. The designed process yields a product with 50 percent of propane and 20 percent of butane, which meets the specification for a high quality LPG.
Sweetening and sulfur recovery of sour associated gas and lean acid gas in th...Frames
Effective and efficient removal of hydrogen sulfide (H2S) is an essential step when sweetening gas for downstream processes. By simultaneously turning the captured hydrogen sulfide into elemental sulfur, a Frames THIOPAQ O&G system improves gas value, while creating a saleable chemical widely sought after in the agricultural and bulk chemical industry.
Sweetening and sulfur recovery of sour associated gas in the middle eastFrames
Effective and efficient removal of hydrogen sulfide (H2S) is an essential step when sweetening gas for downstream processes. By simultaneously turning the captured hydrogen sulfide into elemental sulfur, a Frames THIOPAQ O&G system improves gas value, while creating a saleable chemical widely sought after in the agricultural and bulk chemical industry.
Application: Chemical agents employed in natural gas processing include drilling fluid additives, methanol injection for freeze protection, glycol injection for hydrate inhibition, produced water treatment chemicals, foam and corrosion inhibitors, de-emulsifiers,and drag reduction agents. Chemicals are frequently administered by way of chemical injection skids.
Challenges: Level monitoring controls chemical inventory
and determines when the tanks require filling.The careful
selection and application of level controls to chemical injection systems can effectively protect against tanks running out of chemicals or overfilling.
H2 S and SO2 removal and possible valorizationSerge Vigneron
H2S is a common pollutant in gas and air. This presentation is a review of different techniques to remove H2S ,and possible ways of valorization to sulfuric acid via SO2.
Natural Gas (from a natural reservoir or associated to a crude production) can contain acid gas (H2S and/or CO2)..
The Gas Sweetening Process aims to remove part or all of the acid gas.
Episode 3 : Production of Synthesis Gas by Steam Methane ReformingSAJJAD KHUDHUR ABBAS
Episode 3 : Production of Synthesis Gas by Steam Methane Reforming
History of Synthesis Gas
In 1780, Felice Fontana discovered that combustible gas develops if water vapor is passed over carbon at temperatures over 500 °C. This CO and H2 containing gas was called water gas and mainly used for lighting purposes in the19th century.
As of the beginning of the 20th century, H2/CO-mixtures were used for syntheses of hydrocarbons and then, as a consequence, also called synthesis gas.
Haber and Bosch discovered the synthesis of ammonia from H2 and N2 in 1910 and the first industrial ammonia synthesis plant was commissioned in 1913.
The production of liquid hydrocarbons and oxygenates from syngas conversion over iron catalysts was discovered in 1923 by Fischer and Tropsch.
Much of the syngas conversion processes were being developed in Germany during the first and second world wars at a time when natural resources were becoming scare and alternative routes for hydrogen production, ammonia synthesis, and transportation fuels were a necessity.
In 1943/44, this was applied for large-scale production of artificial fuels from synthesis gas in Germany.
Natural gas processing: Production of LPG Asma-ul Husna
This is a presentation on a process designed for a natural gas processing plant that can use NGL and condensate to produce LPG. The designed process yields a product with 50 percent of propane and 20 percent of butane, which meets the specification for a high quality LPG.
Sweetening and sulfur recovery of sour associated gas and lean acid gas in th...Frames
Effective and efficient removal of hydrogen sulfide (H2S) is an essential step when sweetening gas for downstream processes. By simultaneously turning the captured hydrogen sulfide into elemental sulfur, a Frames THIOPAQ O&G system improves gas value, while creating a saleable chemical widely sought after in the agricultural and bulk chemical industry.
This presentation details out all the process in an Oil Refinery. If you are looking to have a hawk eye view of all the oil refinery process, this presentation will set you on.
Simple explained.
Comparison of Two Dispersion Models_A Bulk Petroleum Storage Terminal Case St...BREEZE Software
"This study presents a comparison of the pollutant concentration predictions from the
AERMOD and ISC air dispersion models in the context of
fugitive storage tank emissions at a bulk petroleum storage terminal."
Case Study: Refinery Relief and Flare StudyFlex Process
Flex Process built dynamic models of all refinery units connected to two flare headers. By making sure the models matched plant performance, and running all identified scenarios, the client was provided with a comprehensive study, including recommendations to ensure a legacy flare header could remain in service, saving £millions in capital expenditure.
Methanal (MeOH) is injected into wet-gas gathering pipeline systems to prevent the formation of hydrates that can be catastrophic to the pipeline, and to reliable production.
There is a tendency to over-injection MeOH as an added insurance against the formation of troublesome hydrate plugs.
Extreme over-injection of MeOH can lead to top-of-line corrosion attack at a high-rate attributed to low pH values of condensing MeOH; trace amounts of strong organic acids are within the condensing MeOH. The corrosion of the pipeline is a "chemical corrosion" reaction as opposed to traditional "electrochemical corrosion" characteristic of other pipeline integrity threats.
There is a fluid dynamic component to the MeOH corrosion mechanism; if the shear-stress of the gas flow is sufficient to shear-off the MeOH droplets from the top surface of the pipeline, the MeOH will not corrode the pipeline, otherwise the droplets of MeOH will sustain a localized, highly corrosive localized environment(s) along the pipeline route.
Abstract A natural gas processing plant separates impurities, nonmethane hydrocarbons, and fluids to produce high-quality pipeline-quality dry natural gas, extracted from underground. Natural gas processing produces valuable byproducts like natural gas liquids (NGLs). The process involves four key steps: oil and condensate removal, water removal, separation of NGLs, and sulfur and carbon dioxide removal. The primary procedures include planning, extraction, separation, removal, and storage. Natural gas sweetening removes CO2 and H2S from natural gas. It involves an amine scrubbing procedure, ensuring H2S and CO2 concentrations are below tariff limits. offers reliable solutions for natural gas sweetening applications. Water is present in natural gas, either in liquid or vapor form. Safe gas processing requires reducing and controlling its water content. .
Natural Gas Processing
4 | P a g e
Introduction
A natural gas processing plant is a facility designed to provide clean raw natural gas by separating impurities, various nonmethane hydrocarbons and fluids to get high quality natural gas, what is known as pipeline-quality dry natural gas. (Speight, J. G.,2019)
Natural gas (or fossil gas) is hiding beneath the surface and extracted both from under the ocean and land. As shown in Figure 1. (Energy Insight, 2023)
Figure 1: Schematic geology of natural gas resources. (Energy Insight, 2023)
natural gas It typically includes heavier hydrocarbons like ethane, propane, normal butane, isobutane, etc. in addition to a significant amount of methane. Additionally, it frequently has a significant proportion of nonhydrocarbons in its raw form, including carbon dioxide, hydrogen sulfide, and nitrogen. Such substances as helium, carbonyl sulfide, and other forms of mercaptan are present in tiny quantities. In generally, it is also saturated with water. Some examples of the analysis of different types of gas are provided in Table 1.
Table 1: Typical Raw Gas Composition. (Mohammed Hamzah Msaed,2021)
Natural Gas Processing
5 | P a g e
Methodology
Natural gas processing yields associated hydrocarbons, sometimes referred to as "natural gas liquids" (NGLs), which can be extremely valuable byproducts. Natural gasoline, propane, butane, isobutane, and ethane are examples of NGLs. These (NGLs) can be purchased individually and are used for a number of purposes, such as improving oil recovery in oil wells, supplying raw materials to petrochemical or oil refineries, and serving as energy sources.
Although the actual process of processing natural gas to pipeline dry gas quality standards might be highly complicated, there are typically four key steps involved in order to eliminate the different impurities: (U.S. Department of Transportation, 2017)
• Oil and Condensate Removal
• Water Removal
• Separation of Natural Gas Liquids
• Sulfur and Carbon Dioxide Removal
While there are several procedures involved in the processing of natural gas, separation, dehydration, removal of ca
Effective Techniques to control gaseous & particulate pollutionShristi Soni
This powerpoint has been made in context to briefly describe about the congtrol methods for gaseous and particulate pollution. This Presentation also briefly describes about the control devices seperately for Gaseous pollution as well as Particulate Pollution.
Hence, this PPT can be very effective way of studying and analysing this Topic
If the material of liner changed with 2RE 69 or Duplex material instead of SS316(urea grade), then passivation air can be reduced, resulting the energy saving because the inerts vented from M.P section and loss of ammonia and problem of pollution. To enhance capacity and energy of the existing plant the internals like vortex mixture and HET may be changed the capacity may increase up to 10-15%.HET, you can changed with super cup.The CO2 and feed top of the vortex mixture nozzle and Ammonia plus carbamate feed from side of the vortex mixture. In the mixing area the initial dispersion of gas and formation of liquid – gas mixture are performed.
Increasing Calorific Value of Biogas using Different Techniques: A Reviewijsrd.com
The use of fossil fuel is increasing day by day and is going to deplete soon. Biogas is a clean environment friendly fuel. Biogas produced from anaerobic digestion of organic waste cannot be utilized straight off as a vehicle fuel. The gases produced from anaerobic digestion are CH4 and trace components like CO2, H2O, H2S, Siloxanes, Hydrocarbons, NH3, O2, CO and N2. To use biogas as fuel, its CV should be about equal to CV of natural gas. Hence CV of biogas can be improved by removing CO2 and trace components from biogas. These gases are not completely combustible and will harm engine parts. For transforming biogas to bioCNG two steps are performed: (1) cleaning process to remove trace components and (2) upgrading process to increase CV of biogas. This paper reviews the attempt made to increase CV of a biogas by different methods for cleaning and upgrading.
The Economic Comparison Between Dry Natural Gas And Nitrogen Gas For Strippin...inventionjournals
Natural gas isa substantial energy source among other sources of fossil fuels. It is usually produced saturated with water vapor under production conditions. The natural gas dehydration is very paramount in the gas industry to stripthe water vapor existing in the gas production, at low-temperature conditions that may plug the system because of hydrate formation in pipelines. Totake off water vapor from natural gas flow usestriethylene glycol (TEG) in the gas dehydration process. In the glycol method, the wet gas is contactwith leanglycolinan absorber to dehydrate naturalgas and the rich glycol will be recovered and used again. This paper deals with stripping gas in the regenerator of glycol dehydration package with part of dry natural gas instead of nitrogen for stripping water vapor from triethylene glycol and studying the economic comparison between both of them by using modeling and simulation with HYSYS program. The two methods were investigated and evaluated to choose the optimal one with respect to the capital and utility costs, provided that keeping the same specifications and quantity of the glycol purity.In addition, the wet gas from the stripping process can be used to operate texsteam pumps and compressors or recycle with wet gas feed. The model has been built according to the actual process flow diagram. Finally, the results of this model could be considered as a basis on which a new heat and material balance will be developed for the plant.
Similar to wednesday pb sir presentation new 1 (20)
2. Natural Gas Processing
Natural-gas processing is a complex industrial process designed to clean raw
natural gas by separating impurities and various non-methane hydrocarbons
and fluids to produce what is known as pipeline quality dry natural
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.
3.
4. 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 .
6. 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.
7.
8. Amine gas treating process is not a selective and must be designed for total
acid-gas removal .
Amine gas treating, also known as amine scrubbing, gas sweetening and
acid 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 CO2
• Methyldiethanolamine: About 30 to 55% % for removing H2S and
CO2
• Diglycolamine: About 50 % for removing H2S and CO2 .
9. 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 + HEAT
MEA + H2O + CO2 MEA CARBONATE + HEAT
REGENERATING REACTON :-
MEA HYDROSULFIDE + HEAT MEA + H2S
MEA CARBONATE + HEAT MEA + H2O + CO2
11. 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 :-
12. Dehydration system :-
1. Direct cooling
2. Compression followed by cooling
3. adsorption
4. 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.
13.
14. 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
15.
16. 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:- cryogenic processing is the norm. This is
a distillation process which utilizes the different volatilities of methane (boiling point of
−161.6°C) and nitrogen (boiling point of −195.69°C) 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 utilizing Pressure 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 (3.8 angstroms). This means nitrogen (3.6 angstroms) is able
to diffuse through the adsorbent, filling adsorption sites, whilst methane is not.
NITROGEN REMOVAL:-
17. 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
23. 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.
Most natural gas production contains, to varying degrees, small (two to eight carbons) hydrocarbon molecules in addition to methane. Although they exist in a gaseous
state at underground pressures, these molecules will become liquid (condense) at normal atmospheric pressure. Collectively, they are called condensates or natural gas liquids (NGLs).
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.
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 .
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.
First two methods does not result in sufficiently low water contents to permit injection into a pipeline .
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.
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 adsorbent
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..
to avoid unnecessary flaring and associated air pollution.
At the high temperature, the glycol loses 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 of
98.0, 98.5, and 98.8 wt % are obtained at 360, 380, and 400 oF, respectively, at one atmosphere pressure.
The higher the gas temperature, the more water it will contain in vapour form.
If the temperature of the wet natural gas is around 140°F 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 40°F 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 130°F. The best results will be obtained between 80 and 110°F .
Increasing the number of trays allows the gas to approach equilibrium with the lean glycol at a lower glycol circulation rate.
