With the number of Liquefied Natural Gas (LNG) liquefaction plants increasing rapidly, it is essential to fully understand what is required to prepare, treat and condition the gas before it can be condensed into LNG for transport and sale. Newpoint Gas is an expert in treating natural gas to make it suitable for feed into an LNG plant, whether that plant is land-based or located on an offshore platform, FPSO or ship.
In an effort to design, engineer and manufacture the most cost effective, space and weight efficient facility possible, many factors must be considered. The first step is determining what detrimental contaminants exist in the entering gas stream. These can include, but are not limited to, oxygen, nitrogen, water, carbon dioxide (CO2), hydrogen sulfide (H2S), mercury, arsenic and heavy hydrocarbons (C3+). Each of these components can create significant problems for the operation of an LNG plant. For example, CO2 content in the gas stream entering an LNG plant must be reduced to less than 50 ppmv to avoid the formation of dry ice within the system, which can plug equipment and shut down the plant. Similarly, mercury in the gas stream can attack the aluminum components often used in LNG plant heat exchangers and other equipment.
Depending on the amount of H2S contained in the inlet gas, an H2S scavenger system may be used to remove the sulfur before the gas enters the rest of the plant. General rules of thumb for choosing an H2S scavenger include:
If none of these general rules apply, it is typically best to remove the H2S later in the treatment process.
Oxygen is typically not found in the gas stream feeding an LNG plant, but this must be verified before proceeding further. If oxygen is present, it must be removed before entering the downstream amine unit, where it would degrade the amine and form heat stable salts and other undesirable byproducts. Newpoint's X-O2, a catalytic reactor system, removes contained oxygen by reacting it with a portion of the inlet hydrocarbon to form CO2 and water. The X-O2 plant can be designed to handle up to 3 percent oxygen with no special requirements or design features and will typically deliver a product stream containing less than 100 ppmv oxygen.
Depending on the amount of CO2 in the inlet gas stream and the volume of gas entering the plant, it can be beneficial to remove the bulk of the CO2 using a membrane treating system, which minimizes the size of the downstream amine plant and reduces the plant's overall energy consumption. For example, a plant with an inlet of 100 MMSCFD of gas containing 10 percent CO2 would require a 1,300 gpm amine plant if amine were the only means used, whereas a two-stage membrane unit could reduce the CO2 to 2 percent and be followed by a 225 gpm amine plant, for an energy consumption equal to only 20 percent of that of the amine plant alone. If a Waste Heat Recovery Unit (WHRU) is available, the system heat input requirement is essentially free, and the membrane system may not be an economical or efficient use of space. Because membranes deal only with the gas phase and involve no liquid hydraulics, membrane systems can be configured in any way necessary to fit within existing plot space limitations and are unaffected by the plant dynamics that can occur in offshore applications.
An amine plant removes essentially all of the CO2 and H2S from the inlet gas stream. For the LNG plant to operate properly and reliably, CO2 should be removed to a level below 50 ppmv, and for the product to be considered sweet, H2S needs to be below 4 ppmv. Amine systems are capable of meeting both criteria. The concentration of these two contaminants and the operating conditions of the plant, including pressure, temperature and remaining gas composition, determine which amine should be used and what circulation rate is required. The amine plant process is essentially identical in every case, though the configuration can usually be adapted to fit within a specified plot area. Because amine systems are liquid systems, care must be taken to ensure the liquid hydraulics are acceptable and that any dynamic movement expected in offshore applications is incorporated into the detailed design of the system.
Once the oxygen, CO2 and H2S have been removed to acceptable levels, the next step is to dry the gas to less than 1 ppmv of H2O. A molecular sieve (mol sieve) dry desiccant is the industry standard for this function. The number of beds is generally determined by the gas volume being dehydrated and the water content in the inlet gas stream. One or more beds operate in the adsorption phase, where water vapor is adsorbed onto the desiccant, while one bed is heat regenerated to strip water from the mol sieve. Regeneration gas can be either a slipstream of dehydrated inlet gas recycled back to the front of the plant for reprocessing, or a stream of residue or off-gas routed to the sales gas line or fuel system after regenerating the mol sieve. Mol sieves can also be designed to remove trace amounts of CO2, H2S and mercaptans, if these contaminants are known to be present. Additionally, if residue gas is used to regenerate the mol sieve, a regenerative mercury removal sieve, such as UOP's HgSieve, can be used to remove mercury from the inlet gas stream at the same time. Properly designed mol sieve systems remove water to less than 1 ppmv, and PLC programming automatically controls switching beds between adsorption and regeneration and between heating and cooling in the regeneration step.
If mercury is present but the regenerative HgSieve is not used for mercury removal, a separate vessel filled with activated carbon typically removes mercury from the gas stream. These beds are usually located downstream of the mol sieve system to keep water from deactivating the bed, and are generally designed to reduce mercury content to less than 10 nanograms per cubic meter. Arsenic removal systems are a virtual duplicate of mercury removal systems in appearance, but use a different bed material to remove arsenic and the various arsines that may be present in the gas stream.
Finally, depending on the quality of the inlet gas and how "clean" an LNG product is desired, the gas may be conditioned to remove heavy-end hydrocarbons before it enters the LNG liquefaction plant. Recovery of these heavy-end hydrocarbons can be accomplished with something as simple as a propane refrigeration plant, up to a full-scale cryogenic gas plant complete with turbo-expander. Depending on the extent to which ethane and heavier components (C2+) are removed, the feed to the LNG liquefaction plant may consist of only methane and nitrogen, with the nitrogen then separated from the methane within the LNG liquefaction plant itself.
Gas pretreatment system design guidance above contributed by W.G. "Trey" Brown.
The residue gas specification in an FLNG or LNG facility of 50 ppmv carbon dioxide (CO2) is a stringent requirement, and amine is the most cost effective and dependable process to meet it. Specialty amines offered by several suppliers also provide hydrogen sulfide (H2S) removal to less than 4 ppmv in the same process, and in many cases, depending on inlet contaminant concentrations, amine may be the only CO2 and H2S removal process required.
Newpoint's modular Amine Regeneration Systems, in an FLNG environment, are designed to use waste heat recovery and sea water for the heating and cooling required in the regeneration process. Making use of these available resources reduces the equipment required, which in turn reduces the physical size of the facility and the weight of the equipment. Newpoint designs and manufactures more gas treating facilities than any other company.
Carbon dioxide and hydrogen sulfide in high concentrations can be among the most expensive contaminants to remove from natural gas. Membrane facilities are often the most cost effective process for bulk removal of these contaminants, with the added advantages of lower energy consumption and less space and weight than other bulk removal processes. The principals of Newpoint have manufactured and operated membrane facilities since 1996.
Mercury is often present in natural gas and is known to damage aluminum heat exchangers, so its removal is required. If mercury is present, Newpoint recommends a mercury removal process capable of reducing the mercury concentration to less than 0.01 micrograms per normal cubic meter. Depending on the concentration of mercury, this process may be integrated into the mol sieve process described above.
Concentrations of less than 1 ppm water are required in an LNG process, and mol sieve is the most effective option to achieve it. Specific mol sieve formulations can also provide CO2 and H2S removal at lower concentrations, if required.
While it is unlikely that oxygen will be present in a natural gas stream feeding an LNG plant, the situation does occur. Newpoint's proprietary X-O2™ process removes oxygen in concentrations up to 4 percent and can be easily integrated into an FLNG or LNG environment.
Explore completed installations that use this process.
Send us your flow rate, inlet contaminant concentrations and required outlet spec. We will size the right process and respond with next steps.
