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The Sorbead™ Quick-Cycle Process
For Simultaneous Removal of Water,
Heavy
Hydrocarbons and Mercaptans from Natural Gas (page 2 of 4)
Figure 4 – A typical 4-vessel Sorbead Quick-Cycle Unit Oil-Drop Silica Gel
Liquid water in gas processing applications can be carried over from the feed stream or “rained” down into the adsorbent when the concentrated water in the regeneration stream condenses should it contact any cool points in the vessel head or piping. In production of BASF Sorbead WS (water stable) adsorbent, the manufacturing conditions are modified to produce a material that is resistant to liquid water without using calcination (excessive heating that reduces a materials capacity). By avoiding calcination, a material with both high capacity and liquid water resistance is produced that is sometimes used to protect the main bed of adsorbent (whether silica gel or molecular sieves).
Conventional granular silica gel is manufactured by mixing the raw materials in a tub and washing to remove impurities. Such production steps and raw materials allows low cost production but at the compromise of a material that is physically damaged by liquid water and one that can be damaged by the stresses of thermal swing adsorption.
One reason that adsorbents have a high capacity for water and heavy hydrocarbons is that within the pores of the adsorbent the impurity turns to liquid in a physical phenomenon termed “capillary condensation”. While the in-pore condensation allows high capacity, it exposes the adsorbent to liquid water and upon heating the expansion due to evaporization can cause physical damage to the adsorbent. BASF Sorbead oil-drop silica gel is highly resistant to such damage.
To determine the impact of the numbers of cycles on a water saturated feed stream on an analytical basis, hydrothermal stability testing has been conducted using pilot plant facilities. In the test, Sorbead oil-drop adsorbent and granular silica gel were exposed to a saturated stream until breakthrough was observed. Once water saturated, the adsorbent bed was regenerated with flow of hot gas and the cycle repeated. The results showed a decrease in the Sorbead oil-drop adsorbent capacity with the first few cycles followed by a flattening of the capacity to relatively stable capacity. The granular silica gel started at similar capacity but quickly dropped about twice the level of the Sorbead adsorbent followed by continual capacity loss. The relative performance is shown in Figure 5.
Figure 5 - Stability study of Sorbead oil-drop silica gel
Typical pipeline specifications for H2S are less than 4 ppm (v) and 2% (mol) for CO2. LNG facilities require the near complete removal of CO2 since it will freeze at the temperatures of LNG.
Heavy hydrocarbons in natural gas can cause foaming of the amine solvent (1) and rich amine can contain considerable amounts of heavy hydrocarbons (2). This operation problem leads to reduced capacity in the amine plant and can lead to turndown of the entire natural gas processing train. While always difficult to quantify the throughput losses, they could rapidly mount to significance.
Use of a quick-cycle unit before the amine plant removes the heavy hydrocarbons and can eliminate the foaming caused by the heavy hydrocarbons (1). This single benefit may be enough to justify the addition of the unit but there are further peripheral benefits that are discussed in this paper.
Reduced Amine Plant VOC emissions in CO2 Removal Amine Plants
BTX and other heavy components have a small but definite solubility in amine solvents (2). Because of this, the amine plant stripper overhead will contain a quantity of heavy hydrocarbons that can include BTX and other heavy hydrocarbon VOC's. In an amine plant for CO2 removal that treats a feed without H2S, the vented CO2 rich stream from the amine stripper can quickly exceed VOC permitting levels dependent on the solubility of the heavy hydrocarbons in the particular amine solvent.Addressing the co-absorbed VOC's can be a major permitting issue and fuel gas assisted flares or catalytic incineration has been used in operating facilities. In such plants, the fuel required for the VOC destruction represents a significant loss of natural gas and has a significant cost.
Thus, using a quick-cycle unit to remove the heavy hydrocarbons before they reach the amine plant ca not only reduce foaming but can eliminate concerns with VOC emissions. It is also possible that the VOC’s must be combusted and this can require the cost for fuel assist or other means for their destruction. (3)
Removal of BTX from Claus Plant Feeds
The destruction of BTX in a Claus plant furnace can require temperature levels that cannot be achieved for a particular sulfur plant feed stream and this is especially the case where the natural gas contains relatively low H2S concentrations. While the use of H2S selective amine formulations can help enrich the H2S, low H2S concentrations in the Claus plant feed is still common for feeds where the H2S concentration is low relative to the CO2 level or in LNG plants where complete CO2 removal is required (leading to dilute H2S concentrations). If the temperature in the Claus plant furnace is insufficient for BTX destruction, the unconverted BTX will carryover into the Claus plant catalyst beds and cause coking and deactivation leading to shortened catalyst life (4).Because BTX adsorbs strongly in the quick-cycle units placement of the quick-cycle unit at the upfront point of the purification train before the amine plant means BTX is not present in the feed to the Claus plant and the downstream catalyst deactivation is mitigated.
Certain Claus plant designs also take advantage of a split flow design wherein a portion of the feed is routed to the furnace and a portion bypassed directly to the Claus catalyst beds. These "split-flow" designs reduce the capital and operating cost of the Claus plant and are attractive for certain ranges of H2S concentration. Where the Claus feed contains BTX such split flow designs are not often chosen since the direct introduction of BTX (present in the stream bypassed around the Claus furnace) causes rapid catalyst degradation. By removing the BTX before the amine plant such a split flow design can be reconsidered.
Mercaptan Removal
Commercial unit field data on the removal of mercaptans with Sorbead quick-cycle units is limited but studies have shown easy removal. Data from Advantica (5) is repeated in Table 1 along with the fundamental conclusions. Since Sorbead quick-cycle units are used to remove C5+ with feed concentrations of C5+ typically 7000 ppm, the mercaptans will have a co-adsorption impact but it is relatively minor in most cases. This is because the mercaptan concentrations are typically lower and the mercaptans have a higher loading. In this study a range of feeds were evaluated and typical heavy compositions in the test are presented in Table 1.Table 1
| Feed composition | |
| Operating pressures | 725 – 1015 psig (50 – 70 bar g) |
| Temperature | 95 F (35 C) |
| Pentane, ppm | 4000 |
| Hexane, ppm | 1500 |
| Heptane, ppm | 300 |
| Octane, ppm | 150 |
| Methyl Mercaptan, ppm | 5 – 20 |
| Ethyl Mercaptan, ppm | 11 – 33 |
| Isopropyl Mercaptan, ppm | 4 – 12 |
| Tertiary-Butyl Mercaptan, ppm | 1 - 3 |
Test Results
- Mercaptans were removed without breakthrough.
- No significant impact of mercaptans on C5+ removal.
- Mercaptans end up in the heavy hydrocarbon condensate.
- A portion of the mercaptans flash from the condensate and are recycled to the feed.
- When treating higher levels of mercaptans, they are expected to be removed but recycle will increase.
The studies conducted by Advantica were in support of a Sorbead quick-cycle unit they designed for the Karachaganak gas field in the Caspian basin since their previous experience was limited to a feed with 10 ppm of mercaptans. While the raw feed can contain up to 2000 ppm, at this site mixed-solvent amine treating precedes the quick-cycle unit and the mercaptan level is 50 ppm at the inlet to the quick-cycle unit. The unit operates at this site though field data is limited.
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