Jun-2018

Modelling ethane absorption in 
MEA solution

Solving foaming problems related to absorption of hydrocarbon and feed contaminants by amine solution.

LEONARDO LEITE GARCIA DE SOUZA, ALVARO LUIZ RIBEIRO SARMET MOREIRA SMIDERLE, IGOR SANCHES MILITÃO 
and MOACIR DE ALCÂNTARA
Petrobras SA

Article Summary

Amine units are largely employed for treating sour streams from natural gas and oil refining operations. This process has been well known since the first half of the last century; it is relatively simple in its processing scheme and not very energy demanding. However, there are still very recent cases reporting troublesome operation of these units with regards to amine solution foaming and carryover, fouling problems and treated/sour gas specification issues. Many of these drawbacks are related to hydrocarbon absorption by the lean amine solution, but there is still very little information available regarding this process and its mathematical modelling. This article presents a troubleshooting case study report of a petrochemical ethane/monoethanolamine (MEA) unit for CO2 removal which, as part of the effort to reduce the hydrocarbon content of the sour gas produced, involved understanding the principles behind the hydrocarbon absorption process and its modelling using available plant data.
Natural gas and petrochemicals

In the last 15 years, Petrobras (Petróleo Brasileiro S.A.), the Brazilian state oil and gas company, has expended a major effort in reducing the country’s dependence on foreign natural gas supplies, mainly from Bolivia, following strong growth in internal demand for environmentally friendly fuels with lower sulphur content (see Figure 1).¹

The majority of Brazilian natural gas is produced from associated offshore oil fields with low API crudes. This is a ‘heavier’ gas in which hydrocarbons such as propane, butane and pentane may have a total content higher than 10 vol%, demanding further processing prior to usage as domestic and automotive fuel in accordance with the legislation from local regulatory agencies.

Natural gas liquids (NGL) produced as by-products of cryogenic gas processing have been historically used as a source of liquefied petroleum gas (LPG/C3-C4) and light naphtha (C5+) suitable for steam cracking, but unsuitable for gasoline production due to low octane number and paraffinicity.

More recently, advances in cryogenic natural gas processing technology and demand for alternative feedstocks for first generation petrochemicals have pushed ethane into the NGL mix. Along with ethane, CO2 and many other contaminants with similar boiling points, such as light alcohols used in offshore gas pipelines as antifreeze agents, have also been pushed into the mix.

Gas processing complex
Duque de Caxias refinery (REDUC), located in Duque de Caxias, Rio de Janeiro, and Cabiúnas gas processing facilities, located in Macaé, Rio de Janeiro, comprise one of the largest gas processing complexes in South America. Together, they process almost all the gas produced from associated offshore oil fields in the south east area of the country (see Figure 2).

REDUC has two natural gas processing units dating from the 1980s and two NGL fractionation units which have been in operation since the beginning of the 2000s. The latter two units fractionate the NGL received from Cabiúnas and generated there by three cryogenic gas processing units. The NGL is pumped through a pipeline of more than 100 km which connects REDUC and Cabiúnas (see Figure 3).                 
The NGL is fractionated into:
•    Ethane, which goes to a petrochemical plant near REDUC
•    Propane, which may go to steam cracking for ethylene production just like ethane or also to LPG
•    Butane, which goes to LPG
•    Isopentane, which goes to high octane gasoline
•    N-pentane and heavier hydrocarbons, which go to petrochemical naphtha (see Figure 3).

Before going to steam cracking, the ethane is treated for CO2 removal in two identical amine units using MEA solution as neutralising agent. These units are located next to the NGL fractionation units.
 
Amine units for CO2 removal
The operation of these units has been troublesome from the start: severe solution foaming and carryover have limited the ethane feed rate to 50-60% of its design value.

Solution foaming is detected by differential pressure transmitters located at the random packing beds of the absorbers. Without further warning, there was a very steep increase in the DP of the beds, followed by large amounts of liquid entrainment that were partially collected by the top knock-out drum and a shortage of liquid to the bottom of the absorber. Amazingly, all the liquid fed to the top of the absorber was almost completely being ‘held’ by the foam inside the voids of the packing beds.

A readily available silicon based antifoam had very limited success; it was able to break down the foam, but it would return less than an hour later. Subsequent lab tests simulating the temperature conditions of the amine units showed that the antifoam deactivated after being submitted to several cycles of heating and cooling.

A closer look at the processing scheme of the units (see Figure 4) drew our attention to two points that later would be confirmed as crucial:
1) The units had no hydrocarbon skimming vessel. It was assumed during basic design that ethane solubility in MEA solution would be negligible and that the CO2 specification (as a beverage gasifier) would be less restrictive in terms of hydrocarbon content.

Hydrocarbon skimming vessels are designed with the purpose of eliminating hydrocarbons absorbed by amine solution during the treatment of sour streams since these could cause solution foaming and degradation. Moreover, by flashing the light hydrocarbons absorbed, these vessels prevent them from distilling along with sour components such as H2S and CO2 at the top of the amine regenerator column, which could cause severe upsets in downstream processes such as sulphur recovery units (SRU).

In the case of the amine units for CO2 removal from ethane, even though less prone to be absorbed due to its lower molecular weight, the ethane content in CO2 at the top of the regenerator column would reach values as high as 20 vol%, making it unsuitable as a beverage gasifier.

2) MEA solution particle filtration was done using cellulose based filtration elements.

According to many references, small solid particles are supposed to make foam stable which makes amine solution filtration a necessity, since MEA and DEA are corrosive agents even in concentrations as low as 15-20 wt%. In our case, design engineering selected cellulose based filtration elements which in retrospect proved to be completely inadequate for the service. After some time, the elements disintegrated under the leaching action of the MEA solution (see Figure 5) and during this process released a ‘foam stabiliser’ component (melamine resin that bonded together the cellulose based filtration elements) which aggravated the foaming problems.²