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Apr-2010

Selecting technologies for onshore 
LNG production

For optimal design of LNG production plants, selection of the individual units must be made on the basis of an integrated approach

Saeid Mokhatab
Tehran Raymand Consulting Engineers

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Article Summary

This article discusses the available process technology options for onshore liquefied natural gas (LNG) production plants, including their limitations and opportunities for integration in order to achieve the right flow scheme that takes advantage of each technology’s strength while maximising integration to minimise capital and operating costs.

A typical scheme for most gas processing plants designed to produce LNG from a sour gas feed is shown in Figure 1. Field production, upon arrival at the processing plant, is processed in a slug catcher, which captures liquid and then allows it to flow into downstream equipment and facilities at a rate at which the liquid can be handled properly. Gas from the outlet of the slug catcher is directed to a high-pressure (HP) separator, where final separation of liquid from the gas takes place. These liquids are stabilised and then stored before sale on the condensates market. The light components stripped in the stabilisation column are recompressed and mixed with the gas from the slug catcher. The aim is to liquefy the resulting raw gas in the downstream process.

The HP raw gas flows through to the gas sweetening unit (GSU), in which acidic components including H2S and CO2 are removed by means of chemical solvents. Simultaneous carbonyl sulphide (COS) removal in the GSU is also desired, as it facilitates the downstream processing and purification steps, and contributes to the reduction of the total sulphur content of the treated gas. The enriched acid gas from the GSU is processed to produce elemental sulphur in a sulphur recovery unit (SRU), consisting of a Claus unit and an associated tail gas treating unit (TGTU) if higher recovery rates are specified for the SRU itself. The final residual gas from the TGTU is incinerated.

The treated sweet gas is then dehydrated on molecular sieves to achieve 1 ppmv water, to ensure safe processing and transmission, and then purified on a mercury guard bed to limit the mercury content to nanogram levels (10 ng/Nm3) and prevent any corrosion problems in the cryogenic section. Mercury is conventionally removed using non-regenerable activated carbon or a regenerative mercury removal sieve, like UOP’s Hg Sieve.

The dry and mercury-free gas is then cooled to about -35°C, where heavy components are liquefied. The cooling temperature is set such that the quantity of these heavy ends, extracted as natural gas liquid (NGL), is adjusted so that the remaining gas composition complies with the LNG specification. Ethane, propane and butane are extracted by fractionation for the refrigerant make-up and for the LPG market. The lean gas is condensed and sub-cooled down to about -160°C to produce LNG.

Generally, the LNG sales specification allows a maximum nitrogen content of about 1% to control the Wobbe Index of import LNG. The nitrogen content of some existing gas fields is above 1%; consequently, the excess nitrogen has to be removed and a dedicated nitrogen removal unit installed. The resulting nitrogen-rich vapour is compressed and fed into the fuel gas system, while the remaining liquid, at about -160°C, is pumped into LNG storage tanks before export by dedicated LNG carriers. Flashed vapours and boil-off gas are recycled within the process.

Technologies for designing an LNG plant
For a given gas composition, different process configurations are available and the choice of technologies can be vast. The number of technology units and how they are integrated significantly impacts overall project economics and success. Therefore, for optimal design of the LNG plant, process selection of the individual units must be made on the basis of an integrated approach that considers interactions between units. The best practice to establish the optimum treating line-up for an LNG production plant should be critically examined, taking all the process and environmental limitations into account within a flexible, operable and economically justified window.

Feed pretreatment section
In a typical scheme for an LNG production plant (see Figure 1), there are several pretreatment units to meet the required specification of the LNG product. The first specifications to be met are H2S removal to <4 ppmv, CO2  to 50 ppmv, total sulphur <30 ppmv as S, water to 0.1 ppmv and mercury to levels of 10 ng/Nm3.

CO2 and H2S in the feed gas significantly impacts the thermal efficiency of any LNG liquefaction process because of the energy required to reduce these contaminants in the context of the energy put into the entire process. In fact, a feed stream with a high concentration of CO2 results in a lower thermal efficiency than one without. The impact of H2S on thermal efficiency is indirectly linked to the CO2 composition (Yates, 2002). Therefore, key elements in selecting the optimum process for the GSU are the requirements for full or selective removal of CO2  and the co-adsorption of hydrocarbons.

Such a unit could be operated with an aqueous amine solvent or mixed physical/chemical solvent. From a sustained development point of view, co-adsorption of hydrocarbons has two unwanted effects. First, it reduces the effectiveness with which the feed gas is used in the downstream process; second, the combustion of hydrocarbons in the SRU results in an increase in CO2 emissions. In the amine treating option, the co-adsorption effect is very low because the solubility of aromatics and heavy hydrocarbons in the aqueous solvent is low. In the mixed-solvent treating option, the co-adsorption effect is much stronger because of the physical solvent element in the GSU solvent.

The second step in the treating process is a MSU, which brings the gas to the final specification for water and mercaptans (RSH) content. Removal of RSH in a MSU necessitates treating the regeneration gas containing RSH in a separate treating unit. There is an optimum between the amine-based GSU and the MSU for mercaptan removal. There are two options: first, mixed physical/chemical processes can be used to remove part or all of the mercaptans from the feed stream, and the MSU can be used as a polishing step. The second option is to use an aqueous amine solvent, which removes some mercaptans (say, 10–15%), leaving most of the mercaptan removal to the MSU.

Importantly, the mechanism for removal of mercaptans in the amine solvents is similar for the hydrocarbons and mercaptans; thus, some degree of co-adsorption of these components cannot be avoided. This optimisation should take into account three main factors: operating flexibility over the feed gas range, environmental performance and cost effectiveness.


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