The purpose of gas-handling, conditioning, and processing facilities is to separate natural gas, condensate, or oil and water from a gas-producing well and condition these fluids for sale or disposal.
The purpose of gas-handling, conditioning, and processing facilities is to separate natural gas, condensate, or oil and water from a gas-producing well and condition these fluids for sale or disposal.
If the fluid temperature from a gas well is low, the flow may have to be heated to a temperature above the hydrate formation temperature before or immediately after the choke. If the gas flow temperature leaving the separators is very hot, it may be necessary to be cooled down to a practical temperature for downstream gas treatment and dehydration. This is because hot gas carries more water vapor which increases the load on the downstream dehydration systems. It can result in a more expensive system than if the gas were cooled first. Besides, the hot temperature could limit the discharge and suction pressure ratio that could be obtained from a downstream separator. Some typical coolers are aerial coolers or a shell-and-tube exchanger.
In this section, we will mainly discuss gas dehydration, sweetening, and processing.
Gas Dehydration
Natural gas may contain water that has to be removed for many reasons. First, at correct pressure and temperature, free water with natural gas can form gas hydrates that can plug valves, fittings, instruments, and pipelines. Second, water vapor increases the volume of the gas which decreases the heating value of gas. Third, condensed water in pipeline can accumulate causing erosion and/or corrosion. Therefore, sales gas, gas plant, and pipeline all require that the water content must meet the specified value.
Dehydration is the process of removing water from the gas stream. The two main methods are adsorption by solid desiccant and absorption by liquid desiccant such as glycol.
Adsorption occurs when water molecules are held at the surface of the solid desiccant by forces of attraction. Some commonly used desiccants are alumina, silica gel, and molecular sieves. The adsorption process is reversible. Adsorption occurs at low temperature and high pressure conditions, while desorption happens at high temperature and low pressure conditions. The adsorption and desorption processes are operated in cycles. During the adsorption process, wet gas flows into the adsorption tower from the top, and dry gas leaves the tower at the bottom. Once the desiccant becomes saturated with water, the tower will be switched to heating or regeneration cycle, during which water is removed and desiccant is dried by heated regenerated gas. Cooling is required after each heating cycle preparing for another adsorbing cycle. Therefore, there are normally at least two towers operating alternatively in adsorption and desorption cycles respectively. Upstream of the adsorption tower, the wet gas first flows through a microfiber inlet filter separator where free liquids, entrained mist, and solid particles are removed, to avoid damage or plug of desiccant bed within the tower.
In the absorption process, the wet gas is dehydrated by liquid desiccants. The most commonly used liquid desiccant is triethylene glycol (TEG). Figure 1 shows a schematic of a typical glycol contactor. First, wet gas flows through an inlet gas scrubber/microfiber filter separator (not shown in the figure) that removes liquid and solid impurities. Then, the gas stream enters the glycol gas contactor near the bottom. The glycol contactor contains several trays with weirs that maintain a specific level of glycol. One of the most commonly used tray configurations is bubble cap trays (shown in the figure). It forces the gas to bubble through the glycol when it flows upward through the holes on the trays. This design increases the contacts between gas and glycol thus enhancing the dehydration process. Before leaving the glycol contactor, the gas passes through a mist exactor that removes liquid entrained in the gas stream. The dry gas leaves at the top of the contactor with a low temperature. After that, it passes through an external glycol gas heat exchanger and cools the incoming dry glycol. The glycol flows downward through the downcomer in the contactor and becomes wetter with water when it flows from top to bottom. After leaving the contactor, the wetted glycol is then dried in the glycol system.
Gas Sweetening
Natural gas can contain acid gases, such as carbon dioxide (CO2), hydrogen sulfide (H2S), and other sulfur compounds like mercaptans. It is crucial to remove these acid gases because they are corrosive and can reduce the heating values. H2S is toxic and can be lethal. The process for removing these acid gases is called “gas sweetening”. Natural gas with H2S and other sulfur compounds is called “sour gas”, while it is called “sweet gas” if it contains no H2S and other sulfur compounds.
There are numerous processes for acid gas removal and gas sweetening. Some typical processes include using solid bed, chemical solvents, physical solvents, and direct conversion of H2S to sulfur.
Solid bed processes use a fixed bed of solid particles to remove acid gases either through chemical reaction or through ionic bonding. Some commonly used processes include iron sponge, sulfa-treat, molecular sieve, and zinc oxide processes. Iron sponge and sulfa-treat both use chemical reactions of ferric oxide with H2S and are mainly applied to gases containing a small amount of H2S. These processes do not remove CO2. The molecular sieve process uses synthetical manufactured crystalline solids to remove gas impurities. It is mainly used for H2S removal in small gas streams at moderate pressures. CO2 may decrease its effectiveness by obstructing the access of H2S and H2O. The zinc oxide process uses chemical reactions of zinc oxide with H2S, however, this process is seldom used due to disposal problems with the spent bed which is classified as a heavy metal salt.
Chemical solvent sweetens natural gas streams through chemical reactions of an aqueous solution of a weak base with acid gases. The aqueous base solution is normally regenerated and circulated to maintain continuous processing. The most common chemical solvents are amines and carbonates. The following figure is a typical flowchart for the amine process. The sour gas enters the absorber at the bottom after an inlet scrubber (not shown in the figure). The inlet scrubber separates the entrained water or hydrocarbon liquids to protect the amine in the absorber. The absorber contains trays, conventional packing, or structured packing to promote acid gas removal. The acid-free gas, also called sweet gas, leaves the absorber at the top. The amine flows downward in the absorber, counter currently with the gas. The rich amine, which contains H2S and CO2, leaves the absorber at the bottom. Sometimes the rich amine also flows through a flash tank (not shown in the figure) which removes most of the dissolved hydrocarbon gases or entrained hydrocarbon condensates. Afterward, the rich amine flows through a heat-exchanger and enters the amine stripping tower, also called regenerator or stripper, at the top. The regenerator is heated by a reboiler system, which breaks the bonds between the amine and acid gases. The acid gases are removed on the top, while the lean amine is circled back to the absorber after cooling. Some most widely industry used amines are alkanolamines diethanolamine (DEA), monoethanolamine (MEA), and methyldiethanolamine (MDEA).
Physical solvent process is based on gas solubility within a solvent instead of chemical reaction as the chemical solvent process is. Fluor solvent process is one type of physical solvent process that uses propylene carbonate to remove CO2 and H2S. Some other licensed processes, such as Sulfinol® Process uses both chemical and physical solvents, which consists of a mixture of tetrahydrothiophene dioxide (Sulfolane®), diisopropanolamine (DIPA), and water. Selexol® process employs the dimethylether of polyethylene glycol as a solvent. The process can remove water and be economical to remove sulfur compounds. However, DIPA may be needed additionally to reduce the CO2 level to pipeline requirement.
The chemical and physical solvent processes are reversible. They generate H2S or SO2 (after flaring), during the solvent regeneration process. Environmental regulations limit the release of H2S to the atmosphere and restrict the amount of SO2 vented or flared. The direct conversion processes oxidize H2S and produce elemental sulfur using chemical reactions. Some typical processes are Stretford process that uses O2 to oxidize H2S, IFP process that is based on the reaction H2S and SO2, LO-CAT® that employs high iron concentration reduction-oxidation technology, Claus process that uses partial oxidation of hydrogen sulfide to sulfur dioxide and catalytically promoted reaction of H2S and SO2 to produce S for high H2S concentration streams, and Sulfa-Check that converts H2S to S in a bubble tower of oxidizing and buffering agents for low H2S concentration streams. It is important to mention that the operating conditions of these processes variate from each other. The designer will need to select the sweetening process based on their operating conditions.
Gas processing
In petroleum, sometimes it is required to separate the Natural Gas Liquid (NGL) to meet heating value requirement. NGL refers to the liquid hydrocarbon, such as ethane, propane, butane, and natural gasoline, which may also have some market values. Liquefied Petroleum Gas (LPG) is a mixture of hydrocarbons, principally butane and propane, and can be transported as a liquid under pressure, or at very low temperatures. It can evaporate quickly at released pressure, and therefore is mainly stored at pressured steel vessels. It is important to distinguish NGL and LPG from liquefied natural gas (LNG). LNG mainly consists of methane, which is liquefied at low temperatures for ease and safety of storage and transportation.
Gas processing normally refers to the process to remove NGL. Some most common processes use lean oil absorption, mechanical refrigeration, Joule-Thomson Expansions, cryogenic (turbo-expander) plants, or combined technologies to separate NGL. The lean oil process uses “lean oil” to absorb the light components in the rich gas streams. The mechanical refrigeration process employs heat exchanger to cool the gas down, while the Joule-Thomson expansion reduces temperature by expanding gas from high to low pressures when it flows across an expansion valve or a choke. To avoid hydrate formation, hydrate inhibitors, such as mono-ethylene glycol (EG), and/or dehydration are required upstream of the cooling processes. Cryogenic plant uses expansion turbine for cooling gas, which is mainly used for improving ethane recovery from natural gas.