Mercury (Hg) exists naturally in oil and gas reservoirs and in gas streams in element or as compound form. The presence of mercury may not be tolerated in certain types of process equipment. Mercury causes severe hazardous corrosion (liquid-metal embrittlement) of aluminum heat exchangers in cryogenic plants, pipes, fittings, and control valves containing non-ferrous metals by amalgam formation. Also, mercury is toxic can easily dissolve in aqueous streams or produced water streams and poison catalysts at the downstream equipment.

Process Description

Mercury removal is a three-stage process. The first stage comprises of natural gas flowing into the inlet gas coalescer for bulk removal of liquid followed by fine removal of liquid in the coalescing section. Liquid droplets of sizes more than 0.3µm are removed to ensure dry gas flows into the mercury removal bed. This is vital for the long life of the bed media.

In the second stage, this liquid-free gas flows into the mercury removal unit, where the elemental mercury is absorbed by proprietary media absorbent (mixed metal sulfides). In the third stage the mercury-free gas is taken to an After Filter to remove any solid dust carried over from the mercury removal bed unit.

CECO Peerless Offer:

• Absolute Separator with High Performance Internals for 99.99% removal of liquid droplets of sizes > 0.3 µm
• Mercury Removal unit
• Post-Bed Dust Filters with long design life and efficiency to remove 100% of particles up to 3 micron
• Optional offer for complete package including Piping, E&I and Structural skid

H2S and CO2 are most common sour (acid) gas contaminants present in natural gas. To make natural gas fit for commercial usage, it is mandatory to remove these containments. The process of removing H2S and CO2 from natural gas is called gas sweetening. Depending upon the process requirements, there are various technologies available to remove H2S and CO2.

Amine based is the most economical and widely used process for Gas Sweetening. However, for smaller flow rates Membrane based or solid bed adsorbent can also be used.

To have an optimum design, the type of amine selected is very important. Peerless can assist customers not only with the correct selection of amine but also design of units from FEED to Commissioning Stage.

We can offer complete package design using any the following amine types.

• MEA (Mono-Ethanol amine)
• DEA (Di-Ethanol amine)
• MDEA (Methyl-di-ethanol amine)
• Specialty Amines

Process Description
1. Amine Absorption Method

The process is essentially a chemical reaction that occurs by contacting lean amine solution with the acid gas in the inlet gas stream in the Amine Absorber at low system pressure.

In the absorber, the downflowing amine solution absorbs H2S and CO2 from the up-flowing sour gas to produce a sweetened gas stream (a gas free of hydrogen sulfide and carbon dioxide) as a product and an amine solution rich in the absorbed acid gases. The resulting “rich” amine then flows into the Amine Flash Drum to remove volatile HC gas. It is then sent to cartridge filters to remove solids and is then taken into the Amine Regenerator (a stripper column with a reboiler) to produce regenerated amine or “lean” amine that is recycled for reuse in the Amine Absorber. The stripped overhead gas from the Regenerator column is a concentrated mix of H2S and CO2 gas.

Heat duty for the reboiler for amine regeneration is provided by either a Hot Oil system or Direct Fired Heaters.

2. Membrane Method

Membrane based acid gas removal is a low-cost method for low gas flowrates. Natural gas, with acid gases, is pre-heated and sent to the membrane unit. The acid gas, H2S and CO2, selectively moves into the permeate phase and while HC gas moves around the membrane and is collected in the export gas stream. H2S removal up to 10 ppm and CO2 removal up to 2–4% is achievable using this process.

3. Absorption Bed Media Method

This method utilizes selective adsorption of H2S and CO2 in a reactant media by moving the gas downflow in the reactor vessel. The H2S and CO2 gas reacts with the bed media to form a chemically stable by- product. This process can be offered in a 1+1 vessel configuration for maximum efficiency and extraction of acid gases. This finds application in low flow and pressure gas such as wellhead gas.

Gas Dehydration is widely used application in Gas Processing Plants. This process is carried out to remove moisture from the natural gas to achieve the required water dew point for pipeline specification or for downstream processing like NGL extraction.

Depending on required outlet guarantee either of the process is selected:

• Glycol Based Gas Dehydration Process
• Molecular Sieve Gas Dehydration Unit

Tri Ethylene Glycol (TEG)-based Gas Dehydration is more widely used and can achieve guarantees up to 3-7lb/ MMSCF of water in treated gas stream. Molecular Sieve Dehydration are used mostly in NGL Plants upstream of cryogenic process.