Mobile Service Reclaiming

Heat stable salts fall into two categories – organic heat stable salts (HSS) and inorganic heat stable salts. Organic HSS form when there is are organic acids in the feed gas stream and/or oxygen degradation fragments of the amine. These organic acids combine irreversibly with the cation form of the amine to form heat stable salt ion pairs that do not get regenerated. These build up over time – removing active amine from service. Other inlet gas contaminants such as hydrogen cyanide and sulphur dioxide can react with the hydrogen sulphide to create thiocyanates and thiosulphates; sulphur dioxide can also go to sulphite or sulphate, depending on the amount of oxygen ingress. These in turn react with the amine to form Inorganic HSS ion pairs. Salty water carry over from upstream separators leaking sea water exchangers and poor quality make-up water can further contribute to the inorganic component contamination load that an amine plant solve can get exposed to and in turn further increase the Inorganic HSS burden. Deliberate addition of sodium or potassium hydroxide can result in high levels of these cations and them contributing to the Inorganic HSS burden.

Examples of these are:

These type of degradation products are derived from reactions with base amine molecule itself and inlet gas components such as carbon dioxide (CO2), carbonyl sulphide (COS), oxygen(O2) and sulphur dioxide (SO2). The amine molecule is broken down or cleaved to change chemical form. These are NOT considered to be ionic contaminants, but are usually called organic degradation products. This physical attack on the amine results in reactions that are for the most part not reversible. If one considers diethanolamine (DEA), the following identify the potential degradation products that can be formed when the DEA reacts with the inlet gas components mentioned above:

Amino acids such as Bicine and Sarcosine are degradation products formed in the presence of DEA and unstable chemical intermediates. They contribute to corrosion in the presence of hydrogen sulphide by inhibiting the formation of the passive iron sulphide layer.  Other degradation products can contribute to solvent corrosivity as well as reduce amine treating capacity by consuming active amine as well as increasing solution viscosity.

• Upstream Pipeline Corrosion Inhibitors (formulated inhibitors)
• Upstream Pipeline Hydrate / Dew Point Control Agents (MEG, TEG)
• Amine System Anti-Foam (Silicone, Polyglycolethers, Oleyl Alcohols)

The upstream materials should be at a minimum but often inlet separator upsets as well as the inherent physical properties of these components will have them enter the amine system and pollute the circulating amine inventory.  There is also the addition of chemicals to the amine system, with the most common being anti-foams (defoamers).  These generally are used more frequently when the solvent degradation becomes more pronounced and the general amine contamination level increases.  Excess amounts of these can actually stabilize the froth in the absorption tower and stripper column and result in foaming.

• Feed Gas Heavy Hydrocarbons
• Upstream Compression Lube Oil
• Amine System Sump Recycling

As with the Upstream and Injection Chemicals these contaminants should also be kept at a minimum if upstream inlet separation is working properly.  Otherwise there is the potential for these to enter the amine system and pollute the circulating amine inventory.  Often the Amine System Sump fluid is simply returned to the circulating inventory without much thought to the potential contaminants that may be present – in particular, pump seal fluid from leaks through the packing or seals as well as fine sand that can get washed into the sump.  These too can contaminate the main amine system and result in system upsets.

• Insoluble Piping Mill Scale
• Sand
• Iron Sulphide
• Charcoal
• Catalyst Fines

All of these can end up in the amine unit either with the inlet fluids, sump recycling, unstable operations resulting in washing contaminants such as iron sulphide off the vessel / contactor walls, corrosion, improper flushing of the charcoal beds.  The particulates can have a serious impact on stabilizing foams which can cause major system upsets as well as result in premature wear on pump internals and piping through their erosive effect.

• Metal Corrosion Ions
• Salt anions and cations
• Excess water

As solvent degradation proceeds, corrosion of the amine plant internals can take place, solubilizing the metals.  These add to the inert solids burden within the circulating inventory.  More detrimental are the salts from poor make-up water and salt water carry-over from inlet separator upsets.  Chlorides can seriously damage stainless steel components through stress corrosion cracking and along with other anions can form ion pairs with the cation form of the amine.  Addition of caustic / carbonates to neutralize heat stable salts may liberate some of the bound amine, but create another issue in regards to increasing the ionic burden in solution and increase solution viscosity.  This in turn can induce the stabilization of foam and can lead to process upsets.  As the water brings in other contaminants with it, the water itself can be considered a contaminant.  The potential for this uncontrolled addition of water to the amine system would effectively dilute the amine concentration and lower the treating capacity of the amine unit.

Solvent Maintenance Strategies:

A.  Solution Replacement

               Complete Inventory

      Partial Volume

B.  Neutralization

C.  Solvent Reclaiming

      Ion Exchange

      Electrodialysis

      Vacuum Distillation

Solution Replacement Options Include:

Complete Replacement

• Dispose & replace contaminated inventory
• Results in improved solution quality
• Will require a unit shutdown
• Highest cost –  both economically and environmentally

Partial Replacement (Bleed & Feed)

• Incremental purges of contaminated solvent and make-up with new product
• Usually marginal improvement in solution quality and amine unit performance
• High cost – both economically and environmentally

When a company has no access to solvent reclaiming, these are the two options most often used in the industry to keep the amine unit operating.

Immediate benefit at deceptively low cost

• Recovers only the capacity lost to bound amine

Delayed price to pay includes

• Need to watch strong cation levels and water concentrations
• Excess Na⁺ (or K⁺) traps HS^– to form NaSH (or KSH)
• NaSH difficult to strip – leads to over stripping & H2S sales product specification problems
• Removal of passivation layer – generates solids that can stabilize foams
• Additional thermal degradation results as reboiler heat transfer surfaces foul
• Solution viscosity increases – participates in foam stabilization

Operators elect to use this approach to either delay the replacement options used in “A.” above and / or solvent reclaiming that is detailed in “C.” below.  Serious consideration has to be given to the negatrive burden that the addition of caustic places on the amine plant pumping horsepower, particulates burden (filter change-outs / foaming) and potential reboiler heat transfer efficiency decline.

Ion Exchange

• MPR

Electrodialysis

• Ucarsep® / Electrosep®

Vacuum Distillation

• CCR Technologies

Limited to ionic species

• Cannot remove amine degradation products

• Partial removal of amino acid degradation products.  For example, Bicine is dipolar so can behave as an anion or a cation depending on the pH of the solution, thereby limiting it total removal

Massive water and chemical requirements

• Must supply DI water, caustic, acid

• Generates huge volumes of chemical waste

Disruptive to plant operation

• Intermittent cycles

• Significant dilution

• Circulating inventory must be re-concentrated

Additional costs often overlooked

• Amine cooler/chiller may be required

• Lean loading removal required before treating

• Energy to boil-off excess water

• Tankage / License Fees

• Usually requires pre-filtration

• Usually required upfront hydrocarbon removal

1.  Limited to ionic species

• Cannot remove amine degradation products

• Partial removal of amino acid degradation products.  For example, Bicine is dipolar so can behave as an anion or a cation depending on the pH of the solution, thereby limiting it total removal

2.  High solution losses

• Cleaner = more make-up amine to purchase

3.  Usually requires pre-filtration

4.  Usually required upfront hydrocarbon removal

5.  May require amine cooler/chiller

6.  Recommended that entire amine system be neutralized in advance for Ucarsep® process

7.  Low levels of contaminants required for Electrosep® process to work

8.  Significant consumption of electricity and is proportional to contaminant load

9.  Huge volumes of waste brine

1.  ALL types of contaminants are simultaneously treated and removed from the solvent

• Heat Stable Salts

• Amine Degradation Products

• Upstream & Injection Chemicals

• Hydrocarbons

• Particulates

• Water & Corrosion Contaminants

2.  Contaminants removed are reduced to smallest possible volume for disposal

• Typically sent to customer’s wastewater plant

• Can be concentrated for incineration if required

• Can be tailored to match deep well disposal requirements

3.  “Invisible” to Operations (steady-state process)

4.  Can handle the majority of gas conditioning solvents currently used in the industry (refer to list at end of document)

5.  Focuses on the solvent, irrespective of the contaminant load or type

Unlike ion exchange and electrodialysis, CCR provides the Complete Acid Gas Removal Solvent Maintenance option to the industry.  By installing a CCR vacuum distillation solvent reclamation system, operators can gain the assurance that their amine systems are have ALL contaminants removed in a single step and that they will be operating at optimum efficiency because their solvent will be at or near virgin solvent specifications.