Natural Gas Refining Technology PDF

Petrochemicals & Petroleum Refining Technology CHAPTER 4 :NATURAL GAS (TREATMENT)  ACID GAS A gas that can form acidic solutions when mixed with water. Common acid gases: 1. Sulfurous gases (Hydrogen Sulfide,H2S and Carbonyl Sulfide, COS)...

Petrochemicals & Petroleum Refining Technology CHAPTER 4 :NATURAL GAS (TREATMENT)  ACID GAS A gas that can form acidic solutions when mixed with water. Common acid gases: 1. Sulfurous gases (Hydrogen Sulfide,H2S and Carbonyl Sulfide, COS) 2. Carbon Dioxide (CO2) These gases cause corrosion (pipelines, reactors, tanks etc). Hydrogen sulfide (H2S) and Carbonyl sulfide (COS) are highly toxic, flammable and explosive. All these gases are contaminants for the environment. ACID GAS  NATURAL GAS H2S : poisonous, corrodes metallic equipment CO2 : reduces heating value, solidify under high pressure and low temperature Acid Gas Removal Plant The sour water stripper (SWS) produces a sour water stripper acid gas stream (SWSAG) that contains hydrogen sulfide (H2S) and ammonia (NH3)  Sulfur Recovery Process H2S commonly used with other gases as a refinery fuel Sulfur dioxide concentrations in flue gases were within acceptable limits Due to regulations which needs the recovery ~99% or more, 2-stages process is required - modified claus - Shell Claus Off-Gas Treatment (SCOT) 1. Modified Claus Process The most practical method for converting H2S to elemental sulphur First reported by Chance and Claus, 1885 The process is depending on the H2S concentrations in NG 90 to 95 percent of recovered sulfur is produced by the Claus process Best suited for acid gas containing 50% or more H2S  Claus Sulfur Process Burner: 2H2S + 3O2 → 2H2O + 2SO2 Reactor: 2H2S + SO2 → 2H2O + 3S Catalysts: Activated aluminum(III) or titanium(IV) oxide Elemental sulphur will be used as fertilizer and pesticide  Carbon-Sulfur Compounds Carbonyl sulphide (COS) and carbon disulphide (CS2) bring problems in Claus operations because they cannot converted completely to sulphur compounds and CO2 Mostly formed during combustion by the reaction of HCs and CO2 Alumina catalyst is more favourable in converting COS and CO2 to elemental sulphur compared to bromide catalyst  2. SCOT Process is designed to remove sulphur compounds from Claus tail gas to comply the air emission regulations Overall sulphur recovery efficiency of 99.9% intake The SCOT units are designed for minimum pressure drop so that they can be easily added to the existing Claus units  CH4+ SO2 → COS + H2O +H2 CO2 + H2 → COS + H2O CH4 + 2S2 → CS2 + 2H2S These compounds which are not converted to S will represent the loss of recoverable sulphur hence increase the emission of sulphur to atmosphere Modifications to the tail gas unit have been designed to reduce these components SCOT Process Acid Gas Treatment Processes Acid Gas Treatment Processes  NATURAL GAS Treatment Processes Purpose: To obtain sweet, dry natural gas by removing acid gases and reducing water vapor Amine Gas Treating Solvent commonly used: MDEA (Methyldiethanolamine) DEA (Diethanolamine) MEA (Monoethanolamine)  TREATMENT PROCESS Chemical Absorption Acid Gas Treament Chemisorption @ Chemical absorption ~ high capability of absorbing large amounts of acid gases. ~ Chemicals used : Monoethanolamine(MEA) Diethanolamine (DEA) Diglycolamine (DGA) ~ solution of relatively weak base  Chemical Absorption Chemisorption Process: Acid gas forms weak bond with the base -easily regenerated Natural gas is passed through amine solution where sulfides, carbonates and bicarbonates are formed  Chemical Absorption Diethanolamine (DEA) ~ favored ~ lower corrosion rate ~ smaller amine loss potential ~ fewer utility requirement ~ minimum reclaiming needs ~ reacts reversibly with 75% of COS while MEA reacts irreversibly with 95% COS and forms degradation that must be disposed of  Chemical Absorption Econamine Process ~ uses Diglycolamine (DGA) ~ low freezing point, suitable for cold climates  Amine Gas Treating Gas stream flow through a liquid solvent, in which the contaminants will be absorbed. Then this solvent - loaded with contaminants - is 'regenerated' by heating or cooling it down: the solvent releases the contaminants. Then, the contaminants can be processed appropriately.  Treatment Processes Physical absorption ~ no chemical reaction ~ solvent (Rectisol, Selexol etc) selectively absorbs acid gases and leaves out the HCs  Selexol & Rectisol Selexol is another type of solvent which can absorb CO2 and thus separate it from the gas stream. Selexol has an advantage over Rectisol that it does not require refrigeration and is therefore less costly, but Selexol cannot achieve the same low Sulfur concentrations as Rectisol. Selexol is overall a less complex process as the Rectisol process. Rectisol is an acid gas which uses a methanol solvent as a means of removing CO2 from a gas stream. Rectisol has a major advantage that it removes COS (Carbonyl Sulfide) and other acid gases while preserving the hydrogen and carbon monoxide in the synthesis gas. Rectisol is a relatively flexible method of removing carbon dioxide and other acid gases during the gasification process. Rectisol can reduce the syngas sulfur content to as low as 2 ppmvd (parts per million by volumetric dry) in the treated gas. However, due to the required refrigeration to cool the methanol, Rectisol can be quite expensive.  TREATMENT PROCESS Physical Absorption SELEXOL Process Solvent: Dimethyl Ether of Polyethylene Glycol For selective removal of H2S, CO2 and other sulfur compounds More effective at acid gas partial pressure above 50 psi High overall sulfur recovery (>99%) Bulk CO2 removal if necessary Reduces overall costs by >4% SELEXOL Process Advantages of SELEXOL Low corrosion rates - No formation of heat Minimal process effluents - Reclaiming and/or purging of solvent not required Protection of downstream equipment - Metal Carbonyls are captured by Selexol Aids in dew point reduction Inert gas can be used for solvent stripping SELEXOL Flowscheme for Sulfur Removal SELEXOL Flowscheme for Sulfur Removal and CO2 Capture  TREATMENT PROCESS Physical Absorption RECTISOL Process A physical wash process where acid gas compounds are solved in methanol and then removed Solvent: Methanol Why methanol? - Cheap, readily available, thermally and chemically stable ~ The main Advantages: i. low utility consumption figures ii. use of a cheap and easily available solvent iii. the flexibility in process configuration.  RECTISOL Process The undesired compounds of the raw gas such as CO2, H2S, COS and other sulphur compounds, HCN, NH3, Ni and iron carbonyls are physically absorbed from the gas by the solvent These components will be stripped, and if required, reboiling of solvent is needed Since the solubility of H2S and organic sulphur compounds are higher than CO2, the H2S concentration in Claus gas can be increased to acceptable levels even the H2S to CO2 ratio in raw gas is low RECTISOL Process  TREATMENT PROCESS Physical Adsorption Acid Gas Treatment Physical Adsorption Adsorbent : solid with high surface area e.g. molecular sieves ~ for low quantity of H2S and CO2 ~ adsorbing water (silica gel)  Treatment Processes WATER REMOVAL In 1,000 cubic meters of gas there can be anything between 10 and over 100 liters of water Purpose: ~ reduce corrosion problem ~ prevent hydrate formation Water Removal Excess moisture in natural gas pipelines can cause the following problems (there are others): As the gas passes through regulators and valves, it will experience a pressure drop and a subsequent temperature drop. Any moisture can freeze and result in blockages.  Light gases can form hydrate compounds in the presence of water. These hydrate compounds can also represent a blockage danger. The carbon dioxide and/or H2S can form corrosive agents if allowed to mix with water. Excess moisture can greatly reduce the heating value of the natural gas. Liquid slugs can form and pass through separators and severally damage compressors.  Water Removal Gas Dehydration Plant ~ reduce corrosion problem ~ prevent hydrate formation Glycol Dehydration Units for removing water vapour from the gas stream down to the pipeline specification. Water vapour absorption is achieved by diethylene glycol (DEG) or triethylene glycol (TEG) contacting wet gas counter currently at stream pressure through an absorption tower. Rich glycol is reconcentrated by heating at atmospheric pressure and recycled to the top of the contactor tower  Water Removal Treatment ~ with glycols : dissolves water efficiently Ethylene Glycol (EG) Diethylene Glycol (DEG) Triethylene Glycol (TEG) Absorption tower  Glycol Dehydration In this process, a liquid desiccant dehydrator serves to absorb water vapor from the gas stream. Glycol, the principal agent in this process, has a chemical affinity for water. This means that, when in contact with a stream of natural gas that contains water, glycol will serve to ‘steal’ the water out of the gas stream. The glycol solution will absorb water from the wet gas. Once absorbed, the glycol particles become heavier and sink to the bottom of the contactor where they are removed. The natural gas, having been stripped of most of its water content, is then transported out of the dehydrator. The glycol solution, bearing all of the water stripped from the natural gas, is put through a specialized boiler designed to vaporize only the water out of the solution. While water has a boiling point of 212°F, glycol does not boil until 400°F. This boiling point differential makes it relatively easy to remove water from the glycol solution, allowing it be reused in the dehydration process.  Solid Dessicant Dehydration Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and usually consists of two or more adsorption towers, which are filled with a solid desiccant. Typical desiccants include activated alumina or a granular silica gel material. Wet natural gas is passed through these towers, from top to bottom. As the wet gas passes around the particles of desiccant material, water is retained on the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto the desiccant material, leaving the dry gas to exit the bottom of the tower.  Solid Dessicant Dehydration Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually installed as a type of straddle system along natural gas pipelines. These types of dehydration systems are best suited for large volumes of gas under very high pressure, and are thus usually located on a pipeline downstream of a compressor station. Two or more towers are required due to the fact that after a certain period of use, the desiccant in a particular tower becomes saturated with water. To ‘regenerate’ the desiccant, a high-temperature heater is used to heat gas to a very high temperature. Water Removal Glycol Dehydration  Compressed Natural Gas (CNG) Compressed Natural Gas (CNG) is a substitute for gasoline (petrol) or diesel fuel. It is made by compressing methane (CH4) extracted from natural gas. It is stored and distributed in hard containers, usually cylinders.  A CNG propelled auto rickshaw on A CNG powered Volvo B10BLE the streets of New Delhi, Delhi. bus, operated by SBS Transit in There is also a fleet of twelve of Singapore. these operating in Brighton, England.  Liquefied Natural Gas (LNG) Liquefied natural gas or LNG is natural gas that has been condensed into a liquid at almost atmospheric pressure (maximum transport pressure set around 25 KPa) by cooling it to approximately -163 °C. LNG is about 1/600th the volume of natural gas at standard temperature and pressure (STP), making it much more cost- efficient to transport over long distances where pipelines do not exist.  Liquefied Natural Gas (LNG) Liquefaction: 1. Expander Cycle 2. Mechanical/ Mixed Refrigeration  Liquefaction system: Expander cycle 1. An expander cycle liquefaction system makes use of a turbo-expander to chill the incoming natural gas stream and liquefy a small portion of that stream. 2. Passing high pressure natural gas through a turbo-expander causes a large decrease in pressure of the gas, resulting in a decrease in temperature of the gas. 3. By passing the chilled natural gas through one or more heat exchangers, a portion of the gas stream can be liquefied. 4. Generally, no more than about 10% of the incoming natural gas stream can be liquefied in an expander cycle.  Liquefaction system: Mixed Refrigerant Cycle 1. The mixed refrigerant cycle uses a mixture of refrigerants (such as propane, ethane, methane, and nitrogen) within a single refrigeration loop. 2. The various stages of refrigeration are accomplished by a series of pressure reduction steps. 3. At each pressure reduction step, the liquid is partially flashed, which produces a colder liquid and vapor. The colder liquid is used as the refrigerant for the next stage of the refrigeration cycle.  Liquefaction system: Mixed Refrigerant Cycle 4. In this way, the mixed refrigerant cycle produces a series of refrigeration loops at different temperatures, much like the cascade cycle. 5. One of the most common types of mixed refrigerant systems uses a separate refrigeration loop, with propane as the refrigerant, to pre-cool the gas feed before it is introduced into the mixed refrigerant system.  Liquefaction system: Mixed Refrigerant Cycle The typical LNG tanker is longer than three football fields and can hold up to 33 million gallons of LNG. It is believed that an explosion on a LNG tanker would have the power of a small nuclear explosion! THANK YOU