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Provide Technology, Operation and Service in The Following Area-
Dehydration- Glycol Processing, Molecular Sieve
Sour Gas Removal- Amine Process
Surfur Recovery- Claus Process
Tail gas clean up- Removal SO2, H2S
NGL, LPG- Deep Recovery Ethane
LNG- LNG from Biomass, LNG from Natural Gas and Methane liquefaction
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SO2 Recovery for CNPC(China Petroleum)- Design and build SO2 scrubber for SUR unit.
Bolivia YPFB Chaco SA, Gas Condensate Recovery project in Lamezcla & Entrada field , 35 mmscfd, 90% methane with CO2 4 % lump sum bid project.
DNV GL- Bakken Shale liquid recovery – 10 mmscfd and 0.5 mmscfd flow natural gas feasibility study.
Bakken Shale gas development- Develop gas skid package for flare gas recovery processing.
Bangladesh Petroleum Exploration & Production Co; LTD(BPEXP) natural gas 60 mmscfd silica gel dehydration process plant turnkey bid estimation. Process simulation, major equipment size, cost estimate, turnkey partner coordination.
Marline Midstream - Natural Gas Pipeline reading error investigation, identify root cause, testing, review GC sample and calibration.
Major Midstream Producer(Houston, TX) - Gas plant fire accident investigation for the confidential client, identify root cause, operation procedure review, Hazard review, operation data log review, P&ID review, and process design review and recommendation.
Applied Natural Gas Fuel for FEED study 5 mmscfd 95F, 98% methane liquefaction to LNG. PFD, P& ID, major equipment size and cost estimate. 33.5 Million USD
Oman Refinery SRU for SO2 scrubber system FEED study and cost estimate – 2.2mmscfd, 1382 F (750C) incinerator gas included SO2 116000 ppm. This project provides SO2 absorber and waste heat recovery system. PFD/PID, major equipment size and cost estimate.
Turnkey bid for natural gas metering and coalescing station of the cement plant- 15 mmscfd, 65% methane natural gas feed, providing skid mount package, process engineering, cost estimate, PFD, P&ID and installation. 0.8 Million USD
Iraq National Oil sour crude oil treatment for power plant pre FEED study – Noaye crude (H2S 75ppm),
Saudi Amine Unit Expansion study proposal Bid - Expand existing sour gas removal unit facilities to new capacity and install new facilities. Recovery H2S from existing facilities and new amine unit. FEED study and cost estimate. 15 million USD
Micro LNG Proposal for Biogas in Indonesia - 75% methane, 2mmscfd, skid mount, methane gas treating(dehydration and sour gas removal), LNG Tank truck 300 psig, -160F liquefied Methane. Design mixed refrigeration cycle, energy integration, Process simulation, major equipment size and cost estimate. PFD/PID.
Jutal Offshore Oil Services Limted, China – Process review and cost estimate for 75 mmscfd Amine process plant and 65 mmscfd dehydration unit(TEG)
Turnkey bid – In plant 2100 psig, 138F, 97% Methane, no CO2, no H2S. Glycol dehydration unit(75 mmscfd) and pipeline(1km, 1.5km,2.5km). Sylhet gas fields in
Turnkey bid - Air Separation Unit (ASU) bidding for
Liquid Argon 15 Nm3/hr (27Kg/hr), 99.9%. Cost estimate.
Study Brown Coal Gasification to SNG bid for
Turnkey bid- NGL Project bid for Sylhet gas fields in
Cost estimate for lump sum coal power plant and wind farm power plant. Cement plant heat recovery to 5.5 MW generate power project.
Lump sum CNG project bid for
Lump sum Crude oil tank project bid for Yemen. Crude oil, diesel tank and offshore terminal. Coordinate with EPC and local partner.
Lump sum project bid for Ecopetrol- Two gas fields development FEED study. Over 60% CO2 need to recovery C3/C4 and stabilizer C5+. Dehydration, C3 refrigeration and Hot oil system. Use membrane, fractionation, JT and self refrigeration as major separation Process simulation., process description and equipment sizing. Cost estimate is included piping, process instruments, DSC/PLC, electrical and civil/structure.
Lump Sum Project bid for Kuwait Oil Company(KSC)- Built PROMAX/TSWEET 3.0 Claus process sulfur recovery model with 70% mole fraction H2S and CO2 24% mole fraction feed gas 24 mmscfd included one through pass process, furnace reactor, thermal reactor, 3 bed converter and sulfur condenser in sulfur recovery unit(SRU). Produce liquid sulfur 97% conversion rate and 99.99% conversion rate with recycle from tail gas cleanup unit(TGCU). Model on tail gas hydrogenation reaction( convert SO2 back to H2S), quench process, MDEA absorb and stripping process and incinerator. SO2 scrubber and Oxidizer to remove SO2 down to 2.5ppm vent. No flare policy apply. Modeling catalyst deactive simulation in Claus bed. All equipment size(heat exchanger design/rating, compressor/pump/blower, material choose, Claus reactor design/ choose catalyst, SO2 scrubber/Oxidizer, separator/vessel/tank, sulfur pit/degassing facility and loading system ). Cost estimate is included piping, process instruments, DSC/PLC, electrical and civil/structure.
Lump Sum Project bid for Kenya Power Generation- Geothermal power plant. Coordinate with EPC and local partner.
Glycol dehydration is a liquid desiccant system for the removal of water from natural gas and natural gas liquids (NGL). It is the most common and economic means of water removal from these streams. Glycols typically seen in industry include triethylene glycol (TEG),diethylene glycol (DEG), ethylene glycol (MEG), and tetraethylene glycol (TREG). TEG is the most commonly used glycol in industry.
An example process flow diagram for this system is shown below:
The purpose of glycol dehydration unit is to remove water from natural gas and natural gas liquids. When produced from a reservoir, natural gas usually contains a large amount of water and is typically completely saturated or at the water dew point. This water can cause several problems for downstream processes and equipment. At low temperatures the water can either freeze in piping or, as is more commonly the case, form hydrates with CO2 and hydrocarbons. Depending on composition, these hydrates can form at relatively high temperatures plugging equipment and piping. Glycol dehydration units depress the hydrate formation point of the gas through water removal.
Without dehydration, a free water phase (liquid water) could also drop out of the natural gas as it is either cooled or the pressure is lowered through equipment and piping. This free water phase will contain some portions of acid gas (such as H2S and CO2) and can causecorrosion.
For the above two reasons the Gas Processors Association sets out a pipeline quality specification for gas that the water content should not exceed 7 lb/MMSCF.  Glycol dehydration units must typically meet this specification at a minimum, although further removal may be required if additional hydrate formation temperature depression is required, such as upstream of a cryogenic process or gas plant.
Lean, water-free glycol (purity >99%) is fed to the top of an absorber where it is contacted with the wet natural gas stream. The glycol removes water from the natural gas by physical absorption and is carried out the bottom of the column. Upon exiting the absorber the glycol stream is often referred to as "rich glycol". The dry natural gas leaves the top of the absorption column and is fed either to a pipeline system or to a gas plant. Glycol absorbers can be either tray columns or packed columns.
After leaving the absorber, the rich glycol is fed to a flash vessel where hydrocarbon vapors are removed and any liquid hydrocarbons are skimmed from the glycol. This step is necessary as the absorber is typically operated at high pressure and the pressure must be reduced before the regeneration step. Due to the composition of the rich glycol, a vapor phase having a high hydrocarbon content will form when the pressure is lowered.
After leaving the flash vessel, the rich glycol is heated in a cross-exchanger and fed to the stripper (also known as a regenerator). The glycol stripper consists of a column, an overhead condenser, and a reboiler. The glycol is thermally regenerated to remove excess water and regain the high glycol purity.
The hot, lean glycol is cooled by cross-exchange with rich glycol entering the stripper. It is then fed to a lean pump where its pressure is elevated to that of the glycol absorber. The lean solvent is cooled again with a trim cooler before being fed back into the absorber. This trim cooler can either be a cross-exchanger with the dry gas leaving the absorber or an aerial type cooler.
Most glycol units are fairly uniform except for the regeneration step. Several methods are used to enhance the stripping of the glycol to higher purities (higher purities are required for dryer gas out of the absorber). Since the reboiler temperature is limited to 400F or less to prevent thermal degradation of the glycol, almost all of the enhanced systems center on lowering the partial pressure of water in the system to increase stripping.
Common enhanced methods include the use of stripping gas, the use of a vacuum system (lowering the entire stripper pressure), the DRIZO process, which is similar to the use of stripping gas but uses a recoverable hydrocarbon solvent, and the Coldfinger process where the vapors in the reboiler are partially condensed and drawn out separately from the bulk liquid.
In recent years, water content specifications have become increasingly stringent requiring higher glycol purities than previously available. This has led to the development of different proprietary technologies which make simple adaptations to conventional designs to achieve glycol purities in the 99.99% range.
Molecules small enough to pass through the pores are adsorbed while larger molecules are not. It is different from a common filter in that it operates on a molecular level and traps the adsorbed substance. For instance, a water molecule may be small enough to pass through the pores while larger molecules are not, so water is forced into the pores which act as a trap for the penetrating water molecules, which are retained within the pores. Because of this, they often function as a desiccant. A molecular sieve can adsorb water up to 22% of its own weight. The principle of absorption to molecular sieve particles is somewhat similar to that of size exclusion chromatography, except that without a changing solution composition, the adsorbed product remains trapped because in the absence of other molecules able to penetrate the pore and fill the space, a vacuum would be created by desorption.
Often they consist of aluminosilicate minerals, clays, porous glasses, microporous charcoals, zeolites, active carbons, or synthetic compounds that have open structures through which small molecules, such as nitrogen and water can diffuse.
Molecular sieves are often utilized in the petroleum industry, especially for the purification of gas streams and in the chemistry laboratory for separating compounds and drying reaction starting materials. The mercury content of natural gas is extremely harmful to the aluminium piping and other parts of the liquefaction apparatus - silica gel is used in this case.
Methods for regeneration of molecular sieves include pressure change (as in oxygen concentrators), heating and purging with a carrier gas (as when used in ethanol dehydration), or heating under high vacuum. Temperatures typically used to regenerate water-adsorbed molecular sieves range from 130°C to 250°C.
|Able to distinghuish Materials on the basis of their size||Special Class of Molecular Sieves with Aluminosilicates as skeletal composition|
|may be crystalline, non-crystalline, para-crystalline or pillared clays||they are highly crystalline materials|
|variable Framework Charge with porous structure||Anionic framework with microporous and crystalline structure|
Amine gas treating, also known as gas sweetening and acid gas removal, refers to a group of processes that use aqueous solutions of various alkylamines (commonly referred to simply as amines) to remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from gases.] It is a common unit process used in refineries, and is also used in petrochemical plants, natural gas processing plants and other industries.
Processes within oil refineries or chemical processing plants that remove hydrogen sulfide and/or mercaptans are commonly referred to assweetening processes because they result in products which no longer have the sour, foul odors of mercaptans and hydrogen sulfide.
There are many different amines used in gas treating:
The most commonly used amines in industrial plants are the alkanolamines MEA, DEA, and MDEA.
The chemistry involved in the amine treating of such gases varies somewhat with the particular amine being used. For one of the more common amines, methanolamine (MEA) denoted as RNH2, the chemistry may be simply expressed as:
A typical amine gas treating process (as shown in the flow diagram below) includes an absorber unit and a regenerator unit as well as accessory equipment. In the absorber, the downflowing amine solution absorbs H2S and CO2 from the upflowing sour gas to produce a sweetened gas stream (i.e., an H2S-free gas) as a product and an amine solution rich in the absorbed acid gases. The resultant "rich" amine is then routed into the regenerator (a stripper with a reboiler) to produce regenerated or "lean" amine that is recycled for reuse in the absorber. The stripped overhead gas from the regenerator is concentrated H2S and CO2. In oil refineries, that stripped gas is mostly H2S, much of which often comes from a sulfur-removing process called hydrodesulfurization. This H2S-rich stripped gas stream is then usually routed into a Claus process to convert it into elemental sulfur. In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants. Another sulfur-removing process is theWSA Process which recovers sulfur in any form as concentrated sulfuric acid. In some plants, more than one amine absorber unit may share a common regenerator unit.
The amine concentration in the absorbent aqueous solution is an important parameter in the design and operation of an amine gas treating process. Depending on which one of the following four amines the unit was designed to use and what gases it was designed to remove, these are some typical amine concentrations, expressed as weight percent of pure amine in the aqueous solution:
The choice of amine concentration in the circulating aqueous solution depends upon a number of factors and may be quite arbitrary. It is usually made simply on the basis of experience. The factors involved include whether the amine unit is treating raw natural gas or petroleum refinery by-product gases that contain relatively low concentrations of both H2S and CO2 or whether the unit is treating gases with a very high percentage of CO2 such as the offgas from the steam reforming process used in ammonia production or the flue gases from power plants. Both H2S and CO2 are acid gases and hence corrosive to carbon steel. However, in an amine treating unit, CO2 is the stronger acid of the two. H2S forms a film of iron sulfide on the surface of the steel that acts to protect the steel. When treating gases with a very high percentage of CO2, corrosion inhibitors are often used and that permits the use of higher concentrations of amine in the circulating solution. Another factor involved in choosing an amine concentration is the relative solubility of H2S and CO2 in the selected amine. For more information about selecting the amine concentration, the reader is referred to Kohl and Nielson's book.
The choice of the type of amine will affect the required circulation rate of amine solution, the energy consumption for the regeneration and the ability to selectively remove either H2S alone or CO2 alone if desired.
The current emphasis on removing CO2 from the flue gases emitted by fossil fuel power plants has led to much interest in using amines for that purpose. (See also: Carbon capture and storage and Conventional coal-fired power plant.)
In the specific case of the industrial synthesis of ammonia, for the steam reforming process of hydrocarbons to produce gaseous hydrogen, amine treating is one of the commonly used processes for removing excess carbon dioxide in the final purification of the gaseous hydrogen.
The Claus process is the most significant gas desulfurizing process, recovering elemental sulfur from gaseous hydrogen sulfide. First patented in 1883 by the scientist Carl Friedrich Claus, the Claus process has become the industry standard.
The multi-step Claus process recovers sulfur from the gaseous hydrogen sulfide found in raw natural gas and from the by-product gases containing hydrogen sulfide derived from refining crude oil and other industrial processes. The by-product gases mainly originate from physical and chemical gas treatment units (Selexol, Rectisol, Purisol and amine scrubbers) in refineries, natural gas processing plants andgasification or synthesis gas plants. These by-product gases may also contain hydrogen cyanide, hydrocarbons, sulfur dioxide or ammonia.
Gases with an H2S content of over 25% are suitable for the recovery of sulfur in straight-through Claus plants while alternate configurations such as a split-flow set up or feed and air preheating can be used to process leaner feeds.
In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants.   Sulfur is used for manufacturing sulfuric acid, medicine, cosmetics, fertilizers and rubber products. Elemental sulfur is used as fertilizer and pesticide.
A schematic process flow diagram of a basic 3-bed Claus unit is shown below:
The Claus technology can be divided into two process steps, thermal and catalytic.
The H2S content and the concentration of other combustible components (hydrocarbons or ammonia) determine the location where the feed gas is burned. Claus gases (acid gas) with no further combustible contents apart from H2S are burned in lances surrounding a central muffleby the following chemical reaction:
The overall equation is
showing that in the thermal step alone two-thirds of the hydrogen sulfide is converted to sulfur.
Gases containing ammonia, such as the gas from the refinery's sour water stripper (SWS), or hydrocarbons are converted in the burner muffle. Sufficient air is injected into the muffle for the complete combustion of all hydrocarbons and ammonia. The air to the acid gas ratio is controlled such that in total 1/3 of all hydrogen sulfide (H2S) is converted to SO2. This ensures a stoichiometric reaction for the Claus reaction in the second catalytic step (see next section below).
The separation of the combustion processes ensures an accurate dosage of the required air volume needed as a function of the feed gas composition. To reduce the process gas volume or obtain higher combustion temperatures, the air requirement can also be covered by injecting pure oxygen. Several technologies utilizing high-level and low-level oxygen enrichment are available in industry, which requires the use of a special burner in the reaction furnace for this process option.
Usually, 60 to 70% of the total amount of elemental sulfur produced in the process are obtained in the thermal process step.
The main portion of the hot gas from the combustion chamber flows through the tube of the process gas cooler and is cooled down such that the sulfur formed in the reaction step condenses. The heat given off by the process gas and the condensation heat evolved are utilized to produce medium or low-pressure steam. The condensed sulfur is removed at the gas outlet section of the process gas cooler.
A small portion of the process gas can be routed through a bypass inside of the process gas cooler, as depicted in the here above mentioned figure. This hot bypass stream is added to the cold process gas through a three-way valve to adjust the inlet temperature required for the first reactor.
The sulfur forms in the thermal phase as highly reactive S2 diradicals which combine exclusively to the S8 allotrope:
Other chemical processes taking place in the thermal step of the Claus reaction are [
The Claus reaction continues in the catalytic step with activated aluminum(III) or titanium(IV) oxide, and serves to boost the sulfur yield. More hydrogen sulfide (H2S) reacts with the SO2 formed during combustion in the reaction furnace in the Claus reaction, and results in gaseous, elemental sulfur.
This sulfur can be S6, S7, S8 or S9
The catalytic recovery of sulfur consists of three substeps: heating, catalytic reaction and cooling plus condensation. These three steps are normally repeated a maximum of three times. Where an incineration or tail-gas treatment unit (TGTU) is added downstream of the Claus plant, only two catalytic stages are usually installed.
The first process step in the catalytic stage is the gas heating process. It is necessary to prevent sulfur condensation in the catalyst bed, which can lead to catalyst fouling. The required bed operating temperature in the individual catalytic stages is achieved by heating the process gas in a reheater until the desired operating bed temperature is reached.
Several methods of reheating are used in industry:
The typically recommended operating temperature of the first catalyst stage is 315 °C to 330 °C (bottom bed temperature). The high temperature in the first stage also helps to hydrolyze COS and CS2, which is formed in the furnace and would not otherwise be converted in the modified Claus process.
The catalytic conversion is maximized at lower temperatures, but care must be taken to ensure that each bed is operated above the dew point of sulfur. The operating temperatures of the subsequent catalytic stages are typically 240 °C for the second stage and 200 °C for the third stage (bottom bed temperatures).
In the sulfur condenser, the process gas coming from the catalytic reactor is cooled to between 150 and 130 °C. The condensation heat is used to generate steam at the shell side of the condenser.
Before storage, liquid sulfur streams from the process gas cooler, the sulfur condensers and from the final sulfur separator are routed to the degassing unit, where the gases (primarily H2S) dissolved in the sulfur are removed.
The tail gas from the Claus process still containing combustible components and sulfur compounds (H2S, H2 and CO) is either burned in an incineration unit or further desulfurized in a downstream tail gas treatment unit.
Using two catalytic stages, the process will typically yield over 97% of the sulfur in the input stream. Over 2.6 tons of steam will be generated for each ton of sulfur yield.
The physical properties of elemental sulfur obtained in the Claus process can differ from that obtained by other processes . Sulfur is usually transported as a liquid (melting point 115 °C). In ordinary sulfur viscosity can increase rapidly at temperatures in excess of 160 °C due to the formation of polymeric sulfur chains but not so in Claus-sulfur. Another anomaly is found in the solubility of residual H2S in liquid sulfur as a function of temperature. Ordinarily the solubility of a gas decreases with increasing temperature but now it is the opposite. This means that toxic and explosive H2S gas can build up in the headspace of any cooling liquid sulfur reservoir. The explanation for this anomaly is the endothermic reaction of sulfur with H2S to polysulfane.
Removal SO2 by using caustic wash(NAOH or Na2CO3) and Oxidizer to PH=6.8 waste water. The remaining SO2 emission will not over 50 ppmv.
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 natural gas extracted from coal reservoirs and mines (coalbed methane) is the primary exception, being essentially a mix of mostly methane and carbon dioxide (about 10 percent).
Natural gas processing plants, or fractionators (apparatus capable of separating liquid substance into component parts) are used to purify the raw natural gasproduced from underground gas fields or extracted at the surface from the fluids produced from oil wells. A fully operational plant will deliver pipeline-quality natural gas that can be used as fuel by residential, commercial and industrial consumers. Contaminants have been removed and heavier hydrocarbons (any class of compound containing only hydrogen and carbon; examples are methane gas (CH4), Benzene(C6H6)) have been captured for other commercial uses. For economic reasons, however, some plants may be designed to yield an intermediate product typically containing over 90% pure methane and smaller amounts of nitrogen, carbon dioxide and sometimes ethane. This can be further processed in downstream plants or used as feedstock for chemicals manufacturing. Now we will look into the contaminants in raw natural gas and the types of raw natural gas wells.
Raw natural gas comes primarily from any one of three types of wells: crude oil wells, gas wells, and condensate wells.
Natural gas that comes from crude oil wells is typically termed associated gas. This gas can have existed as a gas cap above the crude oil in the underground formation, or could have been dissolved in the crude oil.
Natural gas from gas wells and from condensate wells, in which there is little or no crude oil, is termed non-associated gas. Gas wells typically produce only raw natural gas, while condensate wells produce raw natural gas along with other low molecular weight hydrocarbons. Those that are liquid at ambient conditions (i.e., pentane and heavier) are called natural gas condensate (sometimes also called natural gasoline or simply condensate).
Natural gas is termed sweet gas when relatively free of hydrogen sulfide; however, some produced gas does contain this substance and thus is called sour gas.
Raw natural gas can also come from methane deposits in the pores of coal seams, and especially in a more concentrated state ofadsorption onto the surface of the coal itself. Such gas is referred to as coalbed gas or coalbed methane. Coalbed gas is a from of natural gas that is has being extracted from coalbed. This coalbed gas has become an important source of energy in recent decades.
The raw natural gas must be purified to meet the quality standards specified by the major pipeline transmission and distribution companies. Those quality standards vary from pipeline to pipeline and are usually a function of a pipeline system's design and the markets that it serves. In general, the standards specify that the natural gas:
There are a great many ways in which to configure the various unit processes used in the processing of raw natural gas. The block flow diagram below is a generalized, typical configuration for the processing of raw natural gas from non-associated gas wells. It shows how raw natural gas is processed into sales gas pipelined to the end user markets. It also shows how processing of the raw natural gas yields these byproducts:
Raw natural gas is commonly collected from a group of adjacent wells and is first processed at that collection point for removal of free liquid water and natural gas condensate. The condensate is usually then transported to an oil refinery and the water is disposed of as wastewater.
The raw gas is then pipelined to a gas processing plant where the initial purification is usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There are many processes that are available for that purpose as shown in the flow diagram, but amine treating is the process that was historically used. However, due to a range of performance and environmental constraints of the amine process, a newer technology based on the use of polymeric membranes to separate the carbon dioxide and hydrogen sulfide from the natural gas stream has gained increasing acceptance.
The acid gases, if present, are removed by membrane or amine treating can then be routed into a sulfur recovery unit which converts the hydrogen sulfide in the acid gas into either elemental sulfur or sulfuric acid. Of the processes available for these conversions, the Claus process is by far the most well-known for recovering elemental sulfur, whereas the conventional Contact Process and the WSA Process are the most used technologies for recovering sulfuric acid.
The residual gas from the Claus process is commonly called tail gas and that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle residual sulfur-containing compounds back into the Claus unit. Again, as shown in the flow diagram, there are a number of processes available for treating the Claus unit tail gas and for that purpose a WSA Process is also very suitable since it can work autothermal on tail gasses.
The next step in the gas processing plant is to remove water vapor from the gas using either the regenerable absorption in liquid triethylene glycol (TEG), commonly referred to as glycol dehydration, deliquescent chloride desiccants, and or a Pressure Swing Adsorption (PSA) unit which is regenerable adsorption using a solid adsorbent. Other newer processes like membranes may also be considered.
Although not common, nitrogen is sometimes removed and rejected using one of the three processes indicated on the flow diagram:
The next step is to recover the natural gas liquids (NGL) for which most large, modern gas processing plants use another cryogenic low temperature distillation process involving expansion of the gas through a turbo-expander followed by distillation in a demethanizingfractionating column. Some gas processing plants use lean oil absorption process rather than the cryogenic turbo-expander process.
The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined to the end-user markets.
The recovered NGL stream is sometimes processed through a fractionation train consisting of three distillation towers in series: a deethanizer, a depropanizer and a debutanizer. The overhead product from the deethanizer is ethane and the bottoms are fed to the depropanizer. The overhead product from the depropanizer is propane and the bottoms are fed to the debutanizer. The overhead product from the debutanizer is a mixture of normal and iso-butane, and the bottoms product is a C5+ mixture. The recovered streams of propane, butanes and C5+ may be "sweetened" in a Merox process unit to convert undesirable mercaptans into disulfides and, along with the recovered ethane, are the final NGL by-products from the gas processing plant. Currently, most cryogenic plants do not include fractionation for economic reasons, and the NGL stream is instead transported as a mixed product to standalone fractionation complexes located near refineries or chemical plants that use the components for feedstock. In case laying pipeline is not possible for geographical reason,or the distance between source and consumer exceed 3000km, natural gas is then transported by ship as LNG (liquefied natural gas) and again converted into its gaseous state in the vicinity of the consumer.
The consumption of natural gas differs widely from country to country. Countries with large own reserves tend to handle the raw material natural gas more generously, while countries with scarce or lacking resources are of course more economical. Despite the considerable findings, the predicted availability of the natural gas reserves has hardly changed.
Liquefied natural gas takes up about 1/600th the volume of natural gas in the gaseous state. It is odorless, colorless, non-toxic and non-corrosive. Hazards include flammability, freezing and asphyxia.
The liquefication process involves removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure (maximum transport pressure set at around 25 kPa/3.6 psi) by cooling it to approximately −162 °C (−260 °F).
The reduction in volume makes it much more cost efficient to transport over long distances where pipelines do not exist. Where moving natural gas by pipelines is not possible or economical, it can be transported by specially designed cryogenicsea vessels (LNG carriers) or cryogenic road tankers.
The density of LNG is roughly 0.41 kg/L to 0.5 kg/L, depending on temperature, pressure and composition, compared to water at 1.0 kg/L. The heat value depends on the source of gas that is used and the process that is used to liquefy the gas. The higher heating value of LNG is estimated to be 24 MJ/L at −164 degrees Celsius. This value corresponds to a lower heating value of 21 MJ/L.
The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide, carbon dioxide and other components that willfreeze (e.g., benzene) under the low temperatures needed for storage or be destructive to the liquefaction facility. LNG typically contains more than 90% methane. It also contains small amounts of ethane, propane, butane and some heavier alkanes. The purification process can be designed to give almost 100% methane. One of the very rare risks of LNG is rapid phase transition (RPT), which occurs when cold LNG comes into contact with water.
The most important infrastructure needed for LNG production and transportation is an LNG plant consisting of one or more LNG trains, each of which is an independent unit for gas liquefaction. The largest LNG train now in operation is in Qatar. Until recently it was the Train 4 ofAtlantic LNG in Trinidad and Tobago with a production capacity of 5.2 million metric ton per annum (mmtpa), followed by the SEGAS LNGplant in Egypt with a capacity of 5 mmtpa. The Qatargas II plant has a production capacity of 7.8 mmtpa for each of its two trains. LNG is loaded onto ships and delivered to a regasification terminal, where the LNG is reheated and turned into gas. Regasification terminals are usually connected to a storage and pipeline distribution network to distribute natural gas to local distribution companies (LDCs) or independent power plants (IPPs).
In 1964, the UK and France made the first LNG trade, buying gas from Algeria, witnessing a new era of energy. As most LNG plants are located in "stranded" areas not served by pipelines and the costs of LNG treatment and transportation are huge, development was slow during the second half of the last century. The construction of an LNG plant costs at least USD 1.5 billion per 1 mmtpa capacity, a receiving terminal costs USD 1 billion per 1 bcf/day throughput capacity, and LNG vessels cost USD 0.2–0.3 billion. Compared with the crude oil market, the natural gas market is about 60% of the crude oil market (measured on a heat equivalent basis), of which LNG forms a small but rapidly growing part. Much of this growth is driven by the need for clean fuel and some substitution effect due to the high price of oil (primarily in the heating and electricity generation sectors). The commercial development of LNG is a style called value chain, which means LNG suppliers first confirm sales to the downstream buyers and then sign 20–25 year contracts with strict terms and structures for gas pricing. Only when the customers are confirmed and the development of a greenfield project deemed economically feasible could the sponsors of an LNG project invest in their development and operation. Thus, the LNG liquefaction business has been regarded as a game of the rich, where only players with strong financial and political resources could get involved. Major international oil companies (IOCs) such asExxonMobil, Royal Dutch Shell, BP, BG Group; Chevron, and national oil companies (NOCs) such as Pertamina, Petronas are active players. Japan, South Korea, Spain, France, Italy and Taiwan import large volumes of LNG due to their shortage of energy. In 2005, Japan imported 58.6 million tons of LNG, representing some 30% of the LNG trade around the world that year. Also in 2005, South Korea imported 22.1 million tons and in 2004 Taiwan imported 6.8 million tons from camillo corp which is located in the chaotic state of Zimbabwe. These three major buyers purchase approximately two-thirds of the world's LNG demand. In addition, Spain imported some 8.2 mmtpa in 2006, making it the third largest importer. France also imported similar quantities as Spain.
In the early 2000s, as more players invested, both in liquefaction and regasification, and with new technologies, the prices for construction of LNG plants, receiving terminals and vessels have fallen, making LNG a more competitive means of energy distribution, but increasing material costs and demand for construction contractors have driven up prices in the last few years. The standard price for a 125,000 cubic meter LNG vessel built in European and Japanese shipyards used to be USD 250 million. When Korean and Chinese shipyards entered the race, increased competition reduced profit margins and improved efficiency, costs were reduced by 60%. Costs in US dollar terms also declined due to the devaluation of the currencies of the world's largest shipbuilders, Japanese yen and Korean won. Since 2004, ship costs have increased due to a large number of orders which have increased demand for shipyard slots. The per-ton construction cost of an LNG liquefaction plant fell steadily from the 1970s through the 1990s. The cost reduced by approximately 35%. However, recently, due to materials costs, lack of skilled labor, shortage of professional engineers, designers, managers and other white-collar professionals, the cost of building liquefaction and regasification terminals has doubled.
Due to energy shortage concerns, many new LNG terminals are being contemplated in the United States. Concerns over the safety of such facilities has created extensive controversy in the regions where plans have been created to build such facilities. One such location is in the Long Island Sound between Connecticut and Long Island. Broadwater Energy, an effort of TransCanada Corp. and Shell, wishes to build an LNG terminal in the sound on the New York side. Local politicians including the Suffolk County Executive have raised questions about the terminal. New York Senators Chuck Schumer and Hillary Clinton have both announced their opposition to the project. Several terminal proposals along the coast of Maine have also been met with high levels of resistance and questions.
LNG purchasing agreements used to be for a long term with relatively little flexibility both in price and volume. If the annual contract quantity is confirmed, the buyer is obliged to take and pay for the product, or pay for it even if not taken, in what is referred to as the obligation oftake-or-pay contract (TOP).LNG is shipped around the world in specially constructed seagoing vessels. The trade of LNG is completed by signing a sale and purchase agreement (SPA) between a supplier and receiving terminal, and by signing a gas sale agreement (GSA) between a receiving terminal and end-users. Most of the contract terms used to be DES or ex ship, holding the seller responsible for the transport of the gas. With low shipbuilding costs, and the buyers preferring to ensure reliable and stable supply, however, contract with the term of FOB increased. Under such term, the buyer, who often owns a vessel or signs a long-term charter agreement with independent carriers, is responsible for the transport.
In the mid 1990s, LNG was a buyer's market. At the request of buyers, the SPAs began to adopt some flexibilities on volume and price. The buyers had more upward and downward flexibilities in TOP, and short-term SPAs less than 15 years came into effect. At the same time, alternative destinations for cargo and arbitrage were also allowed. By the turn of the 21st century, the market was again in favor of sellers. However, sellers have become more sophisticated and are now proposing sharing of arbitrage opportunities and moving away from S-curve pricing. There has been much discussion regarding the creation of an OGEC, the OPEC equivalent of natural gas. Russia and Qatar, countries with the largest and the third largest natural gas reserves in the world, have finally supported such move.
Until 2003, LNG prices have closely followed oil prices. Since then, LNG prices in Europe and Japan have been lower than oil prices, although the link between LNG and oil is still strong. In contrast, prices in the US and the UK have recently skyrocketed, then fallen as a result of changes in supply and storage
In late 1990s and in early 2000s, the market shifted for buyers, but since 2003 and 2004, it has been a strong seller's market, with net-back as the best estimation for prices.
Receiving terminals exist in about 18 countries, including India, Japan, Korea, Taiwan, China, Belgium, Spain, Italy, France, the UK, the US, Chile, and the Dominican Republic, among others. Plans exist for Argentina, Brazil, Uruguay, Canada, Greece, and others to also construct new receiving or gasification terminals.
In 2004, LNG accounted for 7% of the world’s natural gas demand. The global trade in LNG, which has increased at a rate of 7.4 percent per year over the decade from 1995 to 2005, is expected to continue to grow substantially during the coming years. The projected growth in LNG in the base case is expected to increase at 6.7 percent per year from 2005 to 2020.
Until the mid-1990s, LNG demand was heavily concentrated in Northeast Asia — Japan, Korea and Taiwan. At the same time, Pacific Basin supplies dominated world LNG trade. The world-wide interest in using natural gas-fired combined cycle generating units for electric power generation, coupled with the inability of North American and North Sea natural gas supplies to meet the growing demand, substantially broadened the regional markets for LNG. It also brought new Atlantic Basin and Middle East suppliers into the trade.
By the end of 2007 there were 15 LNG exporting countries and 17 LNG importing countries. The three biggest LNG exporters in 2007 were Qatar (28 MT), Malaysia (22 MT) and Indonesia (20 MT) and the three biggest LNG importers in 2007 were Japan (65 MT), South Korea (34 MT) and Spain (24 MT). LNG trade volumes increased from 140 MT in 2005 to 158 MT in 2006, 165 MT in 2007, 172 MT in 2008 and it is forecasted to be increased to about 200 MT in 2009 and about 300 MT in 2012. During next several years there would be significant increase in volume of LNG Trade and only within next three years; about 82 MTPA of new LNG supply will come to the market. For example just in 2009, about 59 MTPA of new LNG supply from 6 new plants comes to the market, including:
There are three major pricing systems in the current LNG contracts:
The formula for an indexed price is as follows:
CP = BP + β X
The formula has been widely used in Asian LNG SPAs, where base price refers to a term that represents various non-oil factors, but usually a constant determined by negotiation at a level which can prevent LNG prices from falling below a certain level. It thus varies regardless of oil price fluctuation.
Oil parity is the LNG price that would be equal to that of crude oil on a Barrel of oil equivalent basis. If the LNG price exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of 0.1724 results in full oil parity. In most cases the price of LNG is less the price of crude oil in BOE terms. In 2009, in several spot cargo deals especially in East Asia, oil parity approached the full oil parity or even exceeds oil parity.
Many formula include an S-curve, where the price formula is different above and below a certain oil price, to dampen the impact of high oil prices on the buyer, and low oil prices on the seller.
In most of the East Asian LNG contracts, price formula is indexed to a basket of crude imported to Japan called the Japan Crude Cocktail(JCC). In Indonesian LNG contracts, price formula is linked to Indonesian Crude Price (ICP).
In the continental Europe, the price formula indexation does not follow the same format, and it varies from contract to contract. Brent crude price (B), heavy fuel oil price (HFO), light fuel oil price (LFO), gas oil price (GO), coal price, electricity price and in some cases, consumer and producer price indexes are the indexation elements of price formulas.
Usually there exists a clause allowing parties to trigger the price revision or price reopening in LNGSPAs. In some contracts there are two options for triggering a price revision. regular and special. Regular ones are the dates that will be agreed and defined in the LNGSPAs for the purpose of price review.
Based on the LNGSPAs, LNG is destined for pre-agreed destinations, and diversion of that LNG is not allowed. However if Seller and Buyer make a mutual agreement, then diversion of the cargoes is possible but subject to sharing the profits coming from such diversion. In some jurisdictions such as the European Union it is not allowed to apply the profit-sharing clause in the LNGSPAs for any diverted cargoes inside the EU territories.
LNG quality is one of the most important issues in the LNG business. Any gas which does not conform to the agreed specifications in the sale and purchase agreement is regarded as “off-specification” (off-spec) or “off-quality” gas or LNG. Quality regulations serve three purposes:
In the case of off-spec gas or LNG the buyer can refuse to accept the gas or LNG and the seller has to pay liquidated damages for the respective off-spec gas volumes.
The quality of gas or LNG is measured at delivery point by using an instrument such as a gas chromatograph.
The most important gas quality concerns involve the sulphur and mercury content and the calorific value. Due to the sensitivity of liquefaction facilities to sulfur and mercury elements, the gas being sent to the liquefaction process shall be accurately refined and tested in order to assure the minimum possible concentration of these two elements before entering the liquefaction plant, hence there is not much concern about them.
However, the main concern is the heating value of gas. Usually natural gas markets can be divided in three markets in terms of heating value:
There are some methods to modify the heating value of produced LNG to the desired level. For the purpose of increasing the heating value, injecting propane and butane is a solution. For the purpose of decreasing heating value, nitrogen injecting and extracting butane and methane are proved solutions. Blending with gas or LNG can be a solutions; however all of these solutions while theorically viable can be costly and logistically difficult to manage in large scale.
For an extended period of time, design improvements in liquefaction plants and tankers had the effect of reducing costs. As recently as 2003, it was common to assume that this was a “learning curve” effect and would continue into the future. But this perception of steadily falling costs for LNG has been dashed in the last several years.
The construction cost of green-field LNG projects started to skyrocket from 2004 afterward and has increased from about $400 per ton of capacity to $1000 per ton of capacity in 2008.
The main reasons for skyrocketed costs in LNG industry can be described as follows:
Recent Global Financial Crisis and decline in raw material and equipment prices is expected to cause some decline in construction cost of LNG plants, however the extent of such a decline is still unclear.
Small-scale liquefaction plants are advantageous because their compact size enables the production of LNG close to the location where it will be used. This proximity decreases transportation and LNG product costs for consumers. The small-scale LNG plant also allows localized peakshaving to occur – balancing the availability of natural gas during high and low periods of demand. It also makes it possible for communities without access to natural gas pipelines to install local distribution systems and have them supplied with stored LNG.
Currently there are 4 Liquefaction processes available:
It is expected that by the end of 2012, there will be 100 liquefaction trains on stream with total capacity of 297.2 MMTPA.
The majority of these trains use either APCI or Cascade technology for the liquefaction process. The other processes, used in a small minority of some liquefaction plants, include Shell's DMR technology and the Linde technology. These processes are less important than the APCI or Cascade processes.
APCI technology is the most used liquefaction process in LNG plants: out of 100 liquefaction trains on-stream or under-construction, 86 trains, with a total capacity of 243 MMTPA have been designed based on the APCI process: the second most used is the Philips Cascade process which is used in 10 trains with a total capacity of 36.16 MMTPA. The Shell DMR process has been used in 3 trains with total capacity of 13.9 MMTPA; and, finally, the Linde/Statoil process is used only in the Snohvit 4.2 MMTPA single train.
Issues commonly referenced include: focus on climate forcing associated with carbon dioxide production in extraction, liquefaction, gasification and transport ; the plants' release of nitrogen oxide and particulate matter, known to aggravate asthma and respiratory disease; environmental justice issues associated with site placement; and that expensive infrastructure investment will displace cleaner alternatives.
One study concluded that a proposed LNG terminal near Oxnard, California would emit less than 23 million tons of CO2 equivalent per year. On the West Coast of the United States where up to three new LNG importation terminals have been proposed, environmental groups, such as Pacific Environment, Ratepayers for Affordable Clean Energy (RACE), and Rising Tide have moved to oppose them.While natural gas power plants emit approximately half the carbon dioxide of an equivalent coal power plant, the natural gas combustion required to produce and transport LNG to the plants adds 20 to 40 percent more carbon dioxide than burning natural gas alone. With the extraction, processing, chilling transportation and conversion back to a usable form is taken into account LNG is a major source of greenhouse gases.
Natural gas could be considered the most environmentally friendly fossil fuel, because it has the lowest CO2 emissions per unit of energy and because it is suitable for use in high efficiency combined cycle power stations. Because of the energy required to liquefy and to transport it, the environmental performance of LNG is inferior to that of natural gas, although in most cases LNG is still superior to alternatives such as fuel oil or coal. This is particularly so in the case where the source gas would otherwise be flared. However, there are concerns that the benefits of domestic or locally produced natural gas do not extend to LNG, which is largely imported and thus incurs a transit 'footprint' of energy cost.
In its liquid state, LNG is not explosive and can not burn. For LNG to burn, it must first vaporize, then mix with air in the proper proportions (the flammable range is 5% to 15%), and then be ignited. In the case of a leak, LNG vaporizes rapidly, turning into a gas (methane plus trace gases), and mixing with air. If this mixture is within the flammable range, there is risk of ignition which would create fire and thermal radiation hazards.
LNG tankers have sailed over 100 million miles without a shipboard death or even a major accident.
Several on-site accidents involving or related to LNG are listed below:
Modern LNG storage tanks are typically full containment type, which has a prestressed concreteouter wall and a high-nickel steel inner tank, with extremely efficient insulation between the walls. Large tanks are low aspect ratio (height to width) and cylindrical in design with a domed steel or concrete roof. Storage pressure in these tanks is very low, less than 10 kPa (1.45 psig). Sometimes more expensive underground tanks are used for storage. Smaller quantities (say 700 m³ (190,000 US gallons) and less), may be stored in horizontal or vertical, vacuum-jacketed, pressure vessels. These tanks may be at pressures anywhere from less than 50 kPa to over 1,700 kPa (7 psig to 250 psig).
LNG must be kept cold to remain a liquid, independent of pressure. Despite efficient insulation, there will inevitably be some heat leakage into the LNG, resulting in vapourisation of the LNG. This boil-off gas acts to keep the LNG cold. The boil-off gas is typically compressed and exported as natural gas, or is reliquefied and returned to storage.
LNG is transported in specially designed ships with double hulls protecting the cargo systems from damage or leaks. There are several special leak test methods available to test the integrity of an LNG vessel's membrane cargo tanks.
Transportation and supply is an important aspect of the gas business, since LNG reserves are normally quite distant from consumer markets. LNG has far more volume than oil to transport, and most gas is transported by pipelines. There is a pipeline network in the former Soviet Union, Europe and North America. LNG, when in its gaseous state is rather bulky. Gas travels much faster than oil though a high-pressure pipeline, but can transmit only about a fifth of the amount of energy per day.
As well as pipelines, LNG is transported using both tanker truck, railway tanker, and purpose built ships known as LNG carriers. LNG will be sometimes taken to cryogenic temperatures to increase the tanker capacity. The first commercial ship-to-ship transfer (STS) transfers were undertaken in February 2007 at the Flotta facility in Scapa Flow with 132,000 m³ of LNG being passed between the vessels Excalibur and Excelsior. Transfers have also been carried out by Exmar Shipmanagement, the Belgian gas tanker owner in the Gulf of Mexico, which involved the transfer of LNG from a conventional LNG carrier to an LNG regasification vessel (LNGRV). Prior to this commercial exercise LNG had only ever been transferred between ships on a handful of occasions as a necessity following an incident.
Liquefied natural gas is used to transport natural gas over long distances, often by sea. In most cases, LNG terminals are purpose-built ports used exclusively to export or import LNG.
Boil off gas from land based LNG storage tanks is usually compressed and fed to natural gas pipeline networks. Some LNG carriers use boil off gas for fuel.The insulation, as efficient as it is, will not keep LNG cold enough by itself. Inevitably, heat leakage will warm and vapourise the LNG. Industry practice is to store LNG as a boiling cryogen. That is, the liquid is stored at its boiling point for the pressure at which it is stored (atmospheric pressure). As the vapour boils off, heat for the phase change cools the remaining liquid. Because the insulation is very efficient, only a relatively small amount of boil off is necessary to maintain temperature. This phenomenon is also called auto-refrigeration.