A Discussion on the handling of unwanted Trace Components in Gas Processing and Treatment Systems

Raw natural gas typically consists primarily of methane (CH4), the shortest and lightest hydrocarbon molecule.

However, it can also contain varying amounts of a variety of other components including:

• Carbon Dioxide (CO2),
• Hydrogen Sulfide (H2S)
• Water: both water vapor and liquid water.
• Liquid Hydrocarbons
• Dissolved salts and dissolved gases (acids).
• BTEX (Benzene, Toluene, Ethylbenzene, and Xylene)
• Heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i- C4H10), pentanes and even higher molecular weight hydrocarbons.
• Nitrogen (N2)
• Helium (He).
• Mercaptans such as methanethiol (CH3SH) and ethanethiol (C2H5SH).
• Arsenic
• Mercury: both in elemental form, and in compounds such as chlorides, and
• Naturally occurring radioactive material (NORM)

Carbon Dioxide (CO2) and Hydrogen Sulphide (H2S)

As has been covered in a previous discussion, there are a variety of different methods of handling the acid gases Carbon dioxide and Hydrogen sulphide, which depend on:

• The type and concentration of impurities and hydrocarbon composition of the sour gas.
• The temperature and pressure at which sour gas is available
• The outlet gas specification
• The volume of gas to be processed
• Specifications for the residue gas, the acid gas, and liquid products
• The selectivity required for the acid gas removal
• The capital, operating, and royalty costs for the process, and….
• Local environmental constraints.

Whilst membranes can be used for bulk separation of acid gases, removal of low levels of Acid Gas Treatment options include:

• Amine Adsorption Systems
• Alkali Salt Processes
• Physical Absorption Systems
• Molecular sieves
• Cryogenic processes
• Non-regenerable Solid and Liquid Scavengers and
• Biological processes

Water

For removal of water from gas streams to prevent corrosion, liquid slugging, freezing and Hydrate formation, there are different options depending on what you are dealing with:

For water that is present in liquid form as a mist of fine droplets in the gas phase, physical separation processes are the norm, and there are a variety of different types and designs of these systems available.

For water vapor that is present in the gas phase, there are two options

• Absorbent Systems (such as Glycol Stripping) and
• Adsorbent Systems (such as Molecular Sieves)

The choice of absorbent or adsorbent systems will be on a case by case basis dependent depending on the level of dehydration required, the location of operation, and the flow rate and inlet feed composition, but for trace level removal, adsorbent systems are preferred.

I discuss water removal and gas dehydration in this article.

Liquid Hydrocarbons

Liquid Hydrocarbons such as natural-gas condensate (also referred to as casing head gasoline or natural gasoline) and/or crude oil are normally handled in the same manner as liquid water.

i.e. using physical separation processes.

I discuss separation systems in this article.

Dissolved salts and Dissolved gases

The liquid water in the gas phase may contain both dissolved salts and dissolved gases. Temperature and pressure changes may result in these components being released from the liquid water, which can result is additional problems that you will have to handle.

As such, the usual recommendation is to keep these components dissolved in the liquid water, and removal them from the process with the water.

Similarly, it is normally preferable to keep the gases and any other components that are dissolved or emulsified in the liquid hydrocarbons within the liquid hydrocarbon phase and remove them from the system with that phase.

BTEX

BTEX (Benzene, Toluene, Ethyl-benzene, and Xylene) is normally removed from Natural gas as part of Glycol Dehydration or Acid Gas Treatment using Amines.

They then find their way into the vent gas outlets of the systems from the regeneration of the adsorbent and are either….

• Recondensed and recovered as a liquid product for sale or use as fuel,
• Burned off using a flare or incinerator, or
• Adsorbed onto a carbon adsorbent

The methods of addressing BTEX and other emissions are discussed in this article.

Heavier gaseous hydrocarbons

Heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i- C4H10), pentanes and even higher molecular weight hydrocarbons require the gas to be processed at elevanted pressures and reduced temperatures in order for the hydrocarbons to condense out and be separated into their product streams.

When processed and purified into finished by-products, all of these are collectively referred to as Natural Gas Liquids or NGL.

I discuss removal of NGLs in this article.

Nitrogen and Helium

Similarly, Nitrogen and Helium can be removed using cryogenic separation and distillation processes, although the pressures and temperatures involved are a lot more extreme than for removal of hydrocarbons.

Mercaptans

Gas processing often encounters problems with feedstocks containing high levels of mercaptans such as methanethiol (CH3SH), ethanethiol (C2H5SH) and propanethiol (C3H7SH), which concentrate in hydrocarbon condensates and NGL when the mercaptans are not removed.

While hydrogen sulfide (H2S) and carbon dioxide (CO2) are removed by amine treating in most gas plants. When condensates recovered at the gas plant contain high levels of mercaptans, process deficiencies, such as polymeric fouling or solvent contamination, can occur. Therefore, physical solvents or hybrid solvents made of amines with special promoters and activators which are components added to the amine chemistry to enhance and allow the removal of mercaptans and other sulfur species such as Carbonly Sulfide (COS) and Carbonyl Disulfide (CS2).

Additionally, the condensate or its fractionated products often will not meet total sulfur specifications for sales or pipeline transmission until mercaptans are removed from the liquid NGL streams.

Solid Adsorbent systems

Solid Adsorbent systems that employ custom adsorbents are one method for sweetening (i.e. removing mercaptans from) natural gas liquids and Liquified petroleum gas streams. These can reduce the Sulphur content down to low levels when there is no water present. This makes this option attractive for treating demethanizer column bottom products.

Caustic Treating

There are several caustic processes, both regenerative and non-regenerative, that are available to remove sulfur compounds from NGL.

The simplest process uses a solid non-regenerative potassium Hydroxide (KOH) bed. When used in conjunction with methanol injection, Hydrogen sulphide (H2S) and water as well as mercaptans, Carbonyl Sulfide (COS) and Carbon Disulfide can be removed. However, this process is not often used.

Non-regenerative metal oxides (such as Zinc Oxide) are economically attractive if the sulfur rate is less than 500 opund per day (180 kg/day).

One of the most common processes for treating natural gasoline and NGL is the regenerative caustic wash with sodium hydroxide. This usually is located downstream of Amine treatment (or similar) to remove the acid gases and reduce the loading on the caustic wash system

Multiple stages of caustic wash can be used if essentially complete mercaptan removal is necessary.

There are ongoing efforts at different phases of technology development and deployment using liquid chemistries to remove mercaptans from hydrocarbon gas and liquid NGLs.

Mercury

There are two main problems associated with the presence of mercury in natural gas streams: Amalgam formation with aluminium, and Environmental pollution

Elemental mercury distributes between gas and liquid phases. The volatility of elemental mercury and the fact that it will accumulate as it condenses makes removal from the gas stream mandatory in cryogenic plants.

Mercury corrodes brazed-aluminum heat exchangers as it amalgamates with the aluminum to weaken the material.

The mercury compounds concentrate in the hydrocarbon liquids, where they potentially can present environments and safety hazards. The compounds are readily absorbed by most biological systems.

Although mercury in natural gas is normally at low levels, some gases contain sufficiently high mercury concentrations to cause both safety and health concerns.

Southeast Asian gases tend to have higher elemental mercury levels, wheras the US Gulf Coast gases are usually low, but a wide variation can occur within a given region.

Options for mercury removal include both non-regenerative adsorbent systems and regenerative adsorbent systems, which convert the elemental mercury into a less toxic and more easily handled product. However, the complexity of the systems, the adsorbents used, and the level of pre-treatment required all have an impact on the suitability of any Mercury Removal System.

Solid adsorbent systems allow removal of inorganic and organic mercury. The degree of mercury can be increased by initially drying the gas.

Molecular sieves coated with elemental silver are used to trap mercury by amalgamation with the silver.

Arsenic

Arsenic is a toxic nonvolatile solid, but it exists in natural gas primarily as a more volatile trimethylarsine (As(CH3)3)

It usually collects as a fine grey dust. High concentrations tend to be geographically localized.

It can be removed from the gas through a non-regenerative adsorption process, without which the gas streams could not be marketed.

The process requires that the gas be dehydrated to pipeline specifications prior to passing to the adsorbers.

N.O.R.M.

Natural gas can contain Radon, a Naturally occurring radioactive material (NORM), at low concentrations. Whilst Radon seldom causes a problem on its own (it has a half life of about 3.8 days), it does decay into Lead-210, then into Bismuth-210, then into Polonium-210, then into stable Lead-206.

Some of these products, which have long half-lives, can condense on pipe walls and form low-level radioactive scale which can then flake off and collect in filtration systems.

Because of its boiling point, Radon tends to concentrate in propane and propane-ethane mixtures, and storage vessels can accumulate the decay products as low-level radioactive sludge.

Any system that has been contaminated with NORM must be correctly decontaminated and waste disposed of in the correct and approved manner (typically into approved disposal wells).