The use of amine to treat gas and remove acid gas components in an absorption tower (known as an Amine Contactor) is extensively practiced in the petroleum refining and gas processing industries. This is because amine can be regenerated and recycled back into the contactor, making it less operating-expense (OPEX)-intensive, as compared to chemical scavengers (i.e. Triazine). However, this system is not without its disadvantages. First, regenerated amine tends to degrade over time, resulting in the formation of organic acids that corrodes the piping and vessels within the process. Second, the presence of hydrocarbon condensate in amine results in foaming, leading to amine losses and the frequent need to top off the system with fresh amine. Such losses, in severe cases, defeat the OPEX savings achieved by the regeneration of the amine. Furthermore, injection of pH adjusters to regulate the pH levels above the acidic range often result in severely alkaline amine, which aggravates foaming and inorganic scale deposition. This is because the pH adjusting process is very sensitive and prone to operational errors of over injection.
Pure aqueous amine solutions do not foam. It is only in the presence of contaminants such as condensed hydrocarbons, small suspended solids, or other surface active agents such as compressor lube and corrosion inhibitor. When hydrocarbon liquids enter the contactor, they are highly soluble into the amine solution and reduce the surface tension of the aqueous solution. Foaming may occur in the contactor, stripping tower and flash separator.
- If foaming is occurring in the contactor, it is noticeable by a loss in liquid level, a high differential pressure across the tower, high amine carryover, and off spec gas.
- If foaming is occurring in the Flash Separator, it is noticeable by a loss in liquid level, noticeable amine losses from the oil bucket and the inability of the vessel to separate oils and condensates from the amine solution.
- If foaming is occurring in the Stripper, it is noticeable by a high differential pressure across the tower, amine in the overhead accumulator, and poor amine regeneration.
Amine solution foaming is a phenomenon that has been intensively studied and reported. Several foaming root causes have been determined throughout the years; however, the latest experiments suggest that the predominant mechanism for foaming is related to contaminants in the form of surface-active materials, or surfactants. These contaminants can enter the unit in solid, liquid or gas phases and often modify the solution properties in such a way that foam (in gas contactors) and emulsions (in liquid-liquid treaters) are produced, leading to a series of negative effects that cause solution losses and hinder the process from meeting specifications.
To determine if there is a foaming problem, rich and lean amine samples should be analyzed to determine the foam height and break time. Acceptable analysis results are as follows:
- Foam height: between 20 – 30 ml in a graduated cylinder
- Foam break time: Stabilized within 5 – 15 seconds. (Especially in the Lean Sample)
If there is stable foam in the lean sample, there likely is foaming in the absorber tower. Foaming in the absorber leads to high solution losses and off spec gas. If there is stable foam in the rich sample, there likely is foaming in the flash separator and stripper. Foaming in the flash separator leads to solution losses in the oil bucket and the inability to remove liquid hydrocarbon. Foaming in the stripper leads to solution losses in the stripper overhead and poor amine regeneration.
An immediate method to control a foaming problem is the additions of an antifoam at a location just upstream of the foam. Typically, the injection point is at the rich amine outlet of the contactor, upstream of the level control valve.
Effective foam inhibitors from amine sweetening systems are silicone antifoams and polyalkylene glycols. Other antifoams are high boiling point alcohols such as oleyl alcohol and octylphenoxyethanol. It is always important to pull a plant liquid sample and test the antifoam to determine break rates and treatment volumes. Not all antifoams are equal. It is important to determine the most effective antifoam chemical for a particular application.
In general, silicone antifoams have a proven track record. Silicone antifoams are quick and effective at controlling foaming problems; however, they are not without their drawbacks. Silicone antifoams will be absorbed by the activated carbon filters and carried overhead from the regenerator. To prevent this a polyalkylene glycol antifoam may be necessary.
It is important to inject only the prescribed amount of antifoam as recommended by the manufacturer. Excessive antifoam injection can cause more foaming. Systems with poor amine chemistry are typically prone to foaming. A system with poor amine should be set up with continuous injection at a prescribed rate as new contaminants are constantly introduced. Also continuous antifoam injection act as a soap and aid in the removal of contaminants from the system. Batch treating is typically not successful for systems prone to foaming or with poor amine chemistry. If the amine solution chemistry is good and a sample is clean and clear, then batch treating may be appropriate.
To reduce or eliminate the use of antifoam the chemistry of the amine must be improved and the level of contamination in the amine solution must be reduced. It is critical to prevent entrained contaminants in the feed gas from entering the system. This is particularly true with structured packed towers that act as a very efficient filter. Where dirty gas enters the contactor and clean gas exits the contactor, all those contaminants are now entrained in the amine solution.
An inlet separator with mist elimination technology or cyclones in combination with a coalescing filter separator are critical in the capture of these contaminants before they enter the contactor. This equipment should be working efficiently and should not be overloaded.
The Amine regenerator is fitted with mechanical and activated carbon filters as well as a flash separator to maintain a clean solution. These elements however, can become overloaded if the upstream gas separators are not working effectively. To maintain good amine chemistry, it is important to filter, filter, and filter again. Bad chemistry is a sign of poor filtration. It is always good practice to change the filter element prior to a high differential pressure alarm. In many cases, if a high differential pressure alarm is initiated, the filter elements have collapsed and much of the contaminants have become re-entrained in the exiting amine. Of equal importance are the activated carbon filters, if these filters become passivated the chemistry of the solution will become acidic and corrosive. Therefore, it is important to swap carbon filters at regular intervals. Last, the flash separator needs to be working properly, it should be designed with foam baffles and enough residence time to successfully skim liquid hydrocarbon.
A good rule of thumb to prevent liquid hydrocarbon from condensing in the absorber, it is good practice to ensure that the lean amine approach temperature to the tower is held at 10 Deg. F above the temperature of the process gas. If the gas is highly under saturated, hydrocarbon condensation may not be an issue.
In summary, foaming in amine units is a common problem and controlling the foam is critical for stable operation. To control foaming, the chemistry and cleanliness of the amine solution must be maintained. The primary strategy to ensure a well maintained amine solution is to efficiently filter the feed gas and filter the amine solution. If the chemistry of the amine solution is poor and foaming has become a problem, then antifoam injection can immediately control the foaming.