Nitrogen Rejection and C02 Removal Made Easy

Molecular Gate®
Adsorption Technology

The Sorbead™ Quick-Cycle Process For Simultaneous Removal of Water,
Heavy Hydrocarbons and Mercaptans from Natural Gas (page 3 of 4)

Mercaptan Free LPG and COS Formation

Mercaptans are commonly present in natural gas, especially in some of the Middle East and FSU fields that are currently subject to high levels of interest. Mercaptans, if permitted into the amine plant, are partially removed due to their solubility in the amine solvent and, thus are present in both the natural gas overhead product and the acid gas stream.

When the quick-cycle unit removes mercaptans with the water and heavy hydrocarbons before the amine plant, the removed mercaptans are present in the liquid condensate from the quick-cycle unit and thus sour condensate results. Such a condensate can be added to the sour field condensate for treatment.

If not removed upfront, the bulk of the mercaptans permitted into the amine plant is present in the residue natural gas stream, however, due to their solubility in the amine solvent a portion of the mercaptans are also present in the amine plant stripper overhead with the CO2 and H2S. This requires that the mercaptans be converted in the Claus furnace.

The residue natural gas after amine treatment is generally processed for the removal of the higher value LPG components. While a range of mercaptans may be present in the raw natural gas, they tend to concentrate in the LPG liquids extracted and in traditional facilities where these liquid products often require further treatment for the removal of these mercaptans. If mercaptans are largely removed upfront, the downstream treatment can be reduced or potentially eliminated. It is also noteworthy that silica gels causes less COS formation than molecular sieves and dehydration using SORBEAD adsorbent can have advantages in this regard (6).

While this paper does not address the considerations for acid gas removal solvent selection, the removal of mercaptans and heavy hydrocarbons upfront of the amine plant can influence the solvent selected since mercaptan and heavy hydrocarbon solubility in the acid gas treating solvent will be less of an issue. Thus removal of mercaptans and heavy hydrocarbons can affect the selection between the use of chemical amine solvents or mixed chemical/physical solvents.

Mercaptan Free Acid Gas Enrichment Units Vent Stream

In cases where the H2S concentration of the stripper overhead is lean in H2S for a Claus plant feed, as is the case with many LNG and other natural gas plants, an acid gas enrichment unit (AGE) can be used to treat the amine plant acid gases to remove the H2S from the CO2, thus providing a highly enriched H2S stream as feed to the Claus plant. The benefit of the AGE unit is a much higher H2S concentration as feed to the Claus plant leading to capital savings in the Claus plant and operation cost reductions.

While this extra processing step can have advantages, the solubility of the heavy hydrocarbons and mercaptans in the AGE solvent will leave a level of these components in the AGE stripper overhead (CO2 rich stream). This overhead will lower the overall sulfur recovery rate if the mercaptans are not removed and incineration of the CO2 rich vent can also be required which simply routes sulfur to the atmosphere as SO2. Further if this CO2 rich stream requires incineration expensive fuel spiking to combust the mercaptans and heavy hydrocarbons in the stream may be required.

Thus, where an AGE unit is applied, the removal of the heavy hydrocarbons and mercaptans in a quick-cycle unit before the amine treater not only has advantages for the main amine plant but also keeps the heavy hydrocarbons and mercaptans from the AGE stripper overhead and incinerator.

Mercury Removal

Sorbead adsorbents do not have a high affinity for mercury and it mostly passes into the natural gas product stream. When a quick-cycle is placed at the plant inlet, the fact that the product is dry and reduced in heavy hydrocarbons provides advantages to conventional mercury removal arrangement.

Mercury is commonly present in natural gas and, especially in LNG facilities, must be removed to maintain the mechanical integrity of downstream low temperature equipment. While a number of technologies are available for mercury removal, sulfur impregnated activated carbon is commonly used where the mercury is removed onto the bed of adsorbent in a non-regenerable mode where it adsorbs the mercury and is periodically replaced. While activated carbon can treat feeds containing water vapor, the carbon will perform better with a dry feed and the placement of the carbon beds immediately after the quick-cycle system and before the amine plant eliminates the mercury in an early stage of the gas plant.

Removal of the mercury by placing the mercury trapping adsorbent directly after the quick-cycle removal of water and heavy hydrocarbons and before the amine acid gas removal system offers advantages over traditional processing trains because this early removal limits the number of streams into which the mercury fractionates.

Where mercury is not removed upfront of the amine plant it will be present in both the amine plant residue natural gas and the stripper overhead. In a traditional arrangement, where glycol drying of the residue natural gas is used after the amine plant, the mercury will be present in both the dry gas from the glycol unit as well as in the vent stream from the regenerated glycol. Where conventional molecular sieve beds are used for drying the natural gas, mercury can be present in the natural gas product, regeneration stream and the condensed water.

Since mercury is also present in the amine plant stripper overhead, it is also present in the stream that is vented to the atmosphere (where H2S is not present) and also found in the sulfur product where H2S is removed and treated to produce a sulfur product.

Mercury removal upfront is important since it keeps the mercury from splitting in the various process streams resulting from downstream treatment. Please refer to references (7, 8) regarding the discussion on the various points at which mercury is found if it is not removed upstream.

Integrated Dehydration

Placement of the quick-cycle unit near the inlet to the gas conditioning facility has the advantages described. However, it also has an undesirable issue; in that the water dry, heavy hydrocarbon reduced stream sent to the amine plant will be re-saturated with water by the amine solvent.

Conventional approaches to dealing with this water saturated stream include another Sorbead or other adsorbent dryer or glycol dehydration. While Sorbead units deliver lower dew points than conventional glycol units and do not achieve the dew points reached by molecular sieve beds, the fact that a quick-cycle unit exists before the amine plant can allow a cost-effective solution. The water from the amine plant is removed onto an adsorbent bed that has completed its treatment of the raw feed but before it is regenerated. This integration can be best understood by the cycle shown in Figure 6.

Adsorption Raw Feed	Dehydration After Amine	Heat	Cool
Cool	Adsorption Raw Feed	Dehydration After Amine	Heat
Heat	Cool	Adsorption Raw Feed	Dehydration After Amine
Dehydration After Amine	Heat	Cool	Adsorption Raw Feed

Figure 6 - Integrated drying quick-cycle

The cycle is designed such that a first adsorption step "Adsorption Raw Feed" removes water and heavy hydrocarbon from the natural gas and routes the dehydrated and reduced heavy hydrocarbon stream to the amine plant (or an intermediate mercury removal bed followed by the amine plant). The first adsorption step is followed by a second adsorption step "Dehydration after Amine" where the wet natural gas from the amine plant is routed back into a vessel that has completed the initial treatment of the raw feed stream.

Since water adsorbs strongly and the heavy hydrocarbons have already been removed from this stream, only a small incremental amount of adsorbent is required for the removal of the water vapor introduced by the amine plant. The adsorbed water from the second adsorption step will also displace some C5+ into the product stream but the quantity is small since the amount of adsorbent required for the water is small. Note that any displaced C5+ will not have any impact on the amine plant, since the amine plant treats the effluent from the first adsorption step such that effectively the C5+ is bypassed around the amine plant.

Since the integrated heavy hydrocarbon removal requires only one additional vessel, the added cost for the dehydration after the amine plant is roughly 20 percent of the installed cost of the system. However, no units yet operate in this manner and there is a design consideration that the beds will contain a small quantity of H2S and CO2 during the initial “Adsorption Raw Feed” step that can be displaced into the product end by the second “Dehydration after Amine” step and thus bypassing the amine system. This concern can require recycle of this second effluent stream to the amine plant or treatment by a small slipstream of lean amine.


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